Item 7. Management’s Discussion and Analysis
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction
The following discussion and analysis present management’s view of our business, financial condition and overall performance and should be read in conjunction with our consolidated financial statements and footnotes included elsewhere in this filing. Our discussion and analysis consist of the following subjects:
•
Executive Overview
•
Results of Operations
•
Liquidity and Capital Resources
•
Inflation
•
Environmental Regulation
•
Related Party Transactions
•
Summary of Critical Accounting Estimates
•
Recent Accounting Standards
As used in this Item 7, unless the context otherwise requires: "we," "our," "us" and the "Partnership" refer to Natural Resource Partners L.P. and, where the context requires, our subsidiaries. References to "NRP" and "Natural Resource Partners" refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC or any of Natural Resource Partners L.P.’s subsidiaries. References to "Opco" refer to NRP (Operating) LLC, a wholly owned subsidiary of NRP, and its subsidiaries.
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Non-GAAP Financial Measures
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure that we define as net income (loss) less equity earnings from unconsolidated investment, net income attributable to non-controlling interest and gain on reserve swap; plus total distributions from unconsolidated investment, interest expense, net, debt modification expense, loss on extinguishment of debt, depreciation, depletion and amortization and asset impairments. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or loss, net income or loss attributable to partners, operating income or loss, 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 or loss, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDA reported by different companies. In addition, Adjusted EBITDA presented below is not calculated or presented on the same basis as Consolidated EBITDA as defined in our partnership agreement or Consolidated EBITDDA as defined in Opco's debt agreements. See " Item 8. Financial Statements and Supplementary Data—Note 11. Debt, Net " included elsewhere in this Annual Report on Form 10-K for a description of Opco’s debt agreements. Adjusted EBITDA is a supplemental performance measure used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis.
Distributable Cash Flow
Distributable cash flow ("DCF") is a non-GAAP financial measure that we define as 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 and distributions to non-controlling interest. 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") is a non-GAAP financial measure that we define as net cash provided by (used in) operating activities of continuing operations plus distributions from unconsolidated investment in excess of cumulative earnings and return of long-term contract receivables, less maintenance and expansion capital expenditures, cash flow used in acquisition costs classified as investing or financing activities and distributions to non-controlling interest. 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.
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Executive Overview
We are a diversified natural resource company engaged principally in the business of owning, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal and other natural resources and own a non-controlling 49% interest in Sisecam Wyoming LLC ("Sisecam Wyoming"), a trona ore mining and soda ash production business. Our common units trade on the New York Stock Exchange under the symbol "NRP." Our business is organized into two operating segments:
Mineral Rights —consists of approximately 13 million acres of mineral interests and other subsurface rights across the United States. If combined in a single tract, our ownership would cover roughly 20,000 square miles. Our assets provide critical inputs for the manufacturing of steel, electricity and building materials as well as opportunities for carbon sequestration and renewable energy.
Soda Ash —consists of our 49% non-controlling equity interest in Sisecam Wyoming, one of the world's lowest-cost producers of soda ash, an essential ingredient in the manufacturing of glass, solar panels, detergents, and batteries for electric vehicles. Operations are managed by our partner, Sisecam Chemicals Wyoming LLC, and we realize cash flow when distributions are paid to us.
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, 2025 are as follows:
Operating Segments
Corporate and
(In thousands)
Mineral Rights
Soda Ash
Financing
Total
Revenues and other income
$
204,222
$
3,060
$
—
$
207,282
Net income (loss)
$
165,566
$
2,905
$
(32,104
)
$
136,367
Adjusted EBITDA (1)
$
180,523
$
7,685
$
(24,102
)
$
164,106
Cash flow provided by (used in)
Operating activities
$
182,401
$
7,685
$
(24,223
)
$
165,863
Investing activities
$
4,768
$
—
$
—
$
4,768
Financing activities
$
(841
)
$
—
$
(170,093
)
$
(170,934
)
Distributable cash flow (1)
$
187,169
$
7,685
$
(24,223
)
$
170,631
Free cash flow (1)
$
185,286
$
7,685
$
(24,223
)
$
168,748
(1)
See"—Results of Operations" below for reconciliations to the most comparable GAAP financial measures.
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Current Results/Market Commentary
Business Outlook and Quarterly Distributions
We generated $165.9 million of operating cash flow and $168.7 million of free cash flow during the year ended December 31, 2025, and ended the year with $211.2 million of liquidity consisting of $30.1 million of cash and cash equivalents and $181.1 million of borrowing capacity under our Opco Credit Facility. As of December 31, 2025 our leverage ratio was 0.2x.
In February 2025, we paid a cash distribution of $0.75 per common unit of NRP with respect to the fourth quarter of 2024. In March 2025, we paid a special cash distribution of $1.21 per common unit of NRP to help cover unitholder tax liabilities associated with owning NRP's common units in 2024. In May 2025, we paid a cash distribution of $0.75 per common unit of NRP with respect to the first quarter of 2025. In August 2025, we paid a cash distribution of $0.75 per common unit of NRP with respect to the second quarter of 2025. In November 2025, we paid a cash distribution of $0.75 per common unit of NRP with respect to the third quarter of 2025.
In February 2026, the Board of Directors declared and paid a cash distribution of $0.75 per common unit of NRP with respect to the fourth quarter of 2025. Additionally, NRP has announced it will pay special cash distribution of $0.12 in March 2026 to help cover unitholder tax liabilities associated with owning NRP's common units in 2025. Future distributions on our common units will be determined on a quarterly basis by the Board of Directors. The Board of Directors considers numerous factors each quarter in determining cash distributions, including profitability, cash flow, debt service obligations, market conditions and outlook, estimated unitholder income tax liability and the level of cash reserves that the Board of Directors determines is necessary for future operating and capital needs.
Mineral Rights Business Segment
Revenues and other income during the year ended December 31, 2025 decreased $45.7 million, or 18%, as compared to the prior year. Cash provided by operating activities and free cash flow during the year ended December 31, 2025 decreased $59.8 million and $59.5 million, respectively, compared to the prior year. These decreases were primarily due to lower metallurgical coal sales prices and volumes as compared to the prior year in addition to one-time carbon neutral revenues and cash flow in 2024.
Metallurgical and thermal coal prices remained weak throughout 2025 due to sluggish steel demand impacting metallurgical coal and low natural gas prices and ample thermal coal supply at power plants impacting thermal coal. Due to these ongoing factors, we do not expect any material changes to pricing in 2026.
The markets for our carbon neutral revenue opportunities also remain weak. We believe the burdens on the carbon sequestration industry, including insufficient revenue streams, high operational and capital costs, and an uncertain regulatory environment, continue to create formidable barriers that operators have yet to overcome.
Soda Ash Business Segment
Revenues and other income during the year ended December 31, 2025 decreased $15.1 million, or 83%, a s compared to the prior year primarily due to lower soda ash sales prices.
Cash provided by operating activities and free cash flow during the year ended December 31, 2025 decreased $30.9 million as compared to the prior year due to lower cash distributions received from Sisecam Wyoming during the year ended December 31, 2025. We did not receive a cash distribution from Sisecam Wyoming in the third or fourth quarter of 2025.
The soda ash market continues to be significantly oversupplied from the influx of new capacity from China and sales prices remain below the cost of production for most producers. We expect soda ash prices to remain at these lower levels for the foreseeable future and do not expect distributions from Sisecam Wyoming to resume for several years until high-cost capacity is forced to retire. In February 2026, we and Sisecam Wyoming's managing partner agreed to make an additional capital investment into Sisecam Wyoming ($39.2 million for NRP's 49%) to reduce outstanding amounts under Sisecam Wyoming’s bank credit facility and better position it to compete in the current environment. We evaluated this investment as we would any other capital allocation opportunity, with the goal of maximizing NRP's intrinsic value per unit.
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Results of Operations
Year Ended December 31, 2025 and 2024 Compared
Revenues and Other Income
The following table includes our revenues and other income by operating segment:
For the Year Ended December 31,
Percentage
Operating Segment (In thousands)
2025
2024
Decrease
Change
Mineral Rights
$
204,222
$
249,872
$
(45,650
)
(18
)%
Soda Ash
3,060
18,135
(15,075
)
(83
)%
Total
$
207,282
$
268,007
$
(60,725
)
(23
)%
The changes in revenues and other income are discussed for each of the operating segments below:
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Mineral Rights
The following table presents coal sales volumes, coal royalty revenue per ton and coal royalty revenues by major coal producing region, the significant categories of other revenues and other income:
For the Year Ended December 31,
Increase
Percentage
(In thousands, except per ton data)
2025
2024
(Decrease)
Change
Coal sales volumes (tons)
Appalachia
Northern
3,055
1,031
2,024
196
%
Central
12,766
14,137
(1,371
)
(10
)%
Southern
2,208
2,661
(453
)
(17
)%
Total Appalachia
18,029
17,829
200
1
%
Illinois Basin
7,248
5,723
1,525
27
%
Northern Powder River Basin
2,933
2,826
107
4
%
Gulf Coast
953
1,342
(389
)
(29
)%
Total coal sales volumes
29,163
27,720
1,443
5
%
Coal royalty revenue per ton
Appalachia
Northern
$
1.50
$
3.25
$
(1.75
)
(54
)%
Central
6.16
7.13
(0.97
)
(14
)%
Southern
8.86
10.22
(1.36
)
(13
)%
Illinois Basin
2.26
2.26
—
0
%
Northern Powder River Basin
4.71
4.87
(0.16
)
(3
)%
Gulf Coast
0.79
0.80
(0.01
)
(1
)%
Combined average coal royalty revenue per ton
4.58
5.74
(1.16
)
(20
)%
Coal royalty revenues
Appalachia
Northern
$
4,569
$
3,348
$
1,221
36
%
Central
78,640
100,845
(22,205
)
(22
)%
Southern
19,564
27,185
(7,621
)
(28
)%
Total Appalachia
102,773
131,378
(28,605
)
(22
)%
Illinois Basin
16,361
12,927
3,434
27
%
Northern Powder River Basin
13,813
13,768
45
0
%
Gulf Coast
752
1,069
(317
)
(30
)%
Unadjusted coal royalty revenues
133,699
159,142
(25,443
)
(16
)%
Coal royalty adjustment for minimum leases
(187
)
(109
)
(78
)
(72
)%
Total coal royalty revenues
$
133,512
$
159,033
$
(25,521
)
(16
)%
Other revenues
Production lease minimum revenues
$
5,010
$
4,365
$
645
15
%
Minimum lease straight-line revenues
16,576
16,530
46
0
%
Oil and gas royalty revenues
7,622
8,566
(944
)
(11
)%
Carbon neutral revenues
1,454
15,703
(14,249
)
(91
)%
Property tax revenues
6,807
7,100
(293
)
(4
)%
Wheelage revenues
8,361
9,324
(963
)
(10
)%
Coal overriding royalty revenues
2,159
2,358
(199
)
(8
)%
Lease amendment revenues
4,854
3,724
1,130
30
%
Aggregates royalty revenues
3,706
2,904
802
28
%
Other revenues
984
4,542
(3,558
)
(78
)%
Total other revenues
$
57,533
$
75,116
$
(17,583
)
(23
)%
Royalty and other mineral rights
$
191,045
$
234,149
$
(43,104
)
(18
)%
Transportation and processing services revenues
11,295
10,878
417
4
%
Gain on asset sales and disposals
1,882
4,845
(2,963
)
(61
)%
Total Mineral Rights segment revenues and other income
$
204,222
$
249,872
$
(45,650
)
(18
)%
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Coal Royalty Revenues
Approximately 65% of coal royalty revenues and approximately 45% of coal royalty sales volumes were derived from metallurgical coal during the year ended December 31, 2025. Total coal royalty revenues decreased $25.5 million from 2024 to 2025. The discussion by region is as follows:
•
Appalachia : Coal royalty revenues decreased $28.6 million p rimarily due to decreased metallurgical coal sales prices and volumes during the year ended December 31, 2025, as compared to the prior year.
•
Illinois Basin : Coal royalty revenues increased $3.4 million primarily due to higher thermal coal sales volumes during the year ended December 31, 2025, as compared to the prior year.
Other Revenues
Other revenues decreased $17.6 million during the year ended December 31, 2025 as compared to the prior year. This decrease was primarily driven by carbon neutral revenues received in 2024 from a third party related to its creation of California Air Resources Board carbon offset credits from our properties in addition to a $3.6 million decrease in other revenues year-over-year.
Gain on asset sales and disposals
Gain on asset sales and disposals decreased $3.0 m illion during the year ended December 31, 2025 as compared to the prior year primarily as a result of a coal property condemnation in the second quarter of 2024.
Soda Ash
Revenues and other income related to our Soda Ash segment decreased $15.1 million compared to the prior year primarily due to lower sales prices in 2025.
Operating Expenses
The following table presents the significant categories of our consolidated operating expenses:
For the Year Ended December 31,
Percentage
(In thousands)
2025
2024
Decrease
Change
Operating expenses
Operating and maintenance expenses
$
23,854
$
28,036
$
(4,182
)
(15
)%
Depreciation, depletion and amortization
14,955
15,535
(580
)
(4
)%
General and administrative expenses
24,102
25,151
(1,049
)
(4
)%
Asset impairments
20
87
(67
)
(77
)%
Total operating expenses
$
62,931
$
68,809
$
(5,878
)
(9
)%
Total operating expenses decreased $5.9 million primarily due to a $4.2 million decrease in operating and maintenance expenses during the year ended December 31, 2025. The decrease in operating and maintenance expenses was primarily due to lower bad debt expense in 2025 as compared to 2024.
Interest Expense, Net
Interest expense, net decreased $7.6 million during the year ended December 31, 2025 as compared to the prior year primarily due to lower borrowings outstanding on the Opco Credit Facility during the year ended December 31, 2025.
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Adjusted EBITDA (Non-GAAP Financial Measure)
The following table reconciles net income (loss) (the most comparable GAAP financial measure) to Adjusted EBITDA by business segment:
Operating Segments
Corporate and
For the Year Ended (In thousands)
Mineral Rights
Soda Ash
Financing
Total
December 31, 2025
Net income (loss)
$
165,566
$
2,905
$
(32,104
)
$
136,367
Less: equity in earnings from unconsolidated investment
—
(3,060
)
—
(3,060
)
Add: total distributions from unconsolidated investment
—
7,840
—
7,840
Add: interest expense, net
—
—
7,984
7,984
Add: depreciation, depletion and amortization
14,937
—
18
14,955
Add: asset impairments
20
—
—
20
Adjusted EBITDA
$
180,523
$
7,685
$
(24,102
)
$
164,106
December 31, 2024
Net income (loss)
$
206,403
$
17,964
$
(40,723
)
$
183,644
Less: equity in earnings from unconsolidated investment
—
(18,135
)
—
(18,135
)
Add: total distributions from unconsolidated investment
—
38,781
—
38,781
Add: interest expense, net
—
—
15,554
15,554
Add: depreciation, depletion and amortization
15,517
—
18
15,535
Add: asset impairments
87
—
—
87
Adjusted EBITDA
$
222,007
$
38,610
$
(25,151
)
$
235,466
Net income decreased $47.3 million as compared to the prior year primarily due to the decrease in revenues and other income, partially offset by lower operating and interest expenses, all as discussed above. Adjusted EBITDA decreased $71.4 million as compared to the prior year primarily due to a $41.5 million decrease in Adjusted EBITDA within our Mineral Rights segment as a result of lower revenues and other income during the year ended December 31, 2025 as discussed above and a $30.9 million decrease in Adjusted EBITDA within our Soda Ash segment driven by lower cash distributions received from Sisecam Wyoming during the year ended December 31, 2025.
Distributable Cash Flow ("DCF") and Free Cash Flow ("FCF") (Non-GAAP Financial Measures)
The following table presents the three major categories of the statement of cash flows by business segment:
Operating Segments
Corporate and
For the Year Ended (In thousands)
Mineral Rights
Soda Ash
Financing
Total
December 31, 2025
Cash flow provided by (used in)
Operating activities
$
182,401
$
7,685
$
(24,223
)
$
165,863
Investing activities
4,768
—
—
4,768
Financing activities
(841
)
—
(170,093
)
(170,934
)
December 31, 2024
Cash flow provided by (used in)
Operating activities
$
242,168
$
38,610
$
(32,285
)
$
248,493
Investing activities
7,511
—
—
7,511
Financing activities
(1,086
)
—
(236,463
)
(237,549
)
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The following tables reconcile net cash provided by (used in) operating activities (the most comparable GAAP financial measure) by business segment to DCF and FCF:
Operating Segments
Corporate and
For the Year Ended (In thousands)
Mineral Rights
Soda Ash
Financing
Total
December 31, 2025
Net cash provided by (used in) operating activities
$
182,401
$
7,685
$
(24,223
)
$
165,863
Add: proceeds from asset sales and disposals
1,883
—
—
1,883
Add: return of long-term contract receivable
2,885
—
—
2,885
Distributable cash flow
$
187,169
$
7,685
$
(24,223
)
$
170,631
Less: proceeds from asset sales and disposals
(1,883
)
—
—
(1,883
)
Free cash flow
$
185,286
$
7,685
$
(24,223
)
$
168,748
December 31, 2024
Net cash provided by (used in) operating activities
$
242,168
$
38,610
$
(32,285
)
$
248,493
Add: proceeds from asset sales and disposals
4,846
—
—
4,846
Add: return of long-term contract receivable
2,665
—
—
2,665
Distributable cash flow
$
249,679
$
38,610
$
(32,285
)
$
256,004
Less: proceeds from asset sales and disposals
(4,846
)
—
—
(4,846
)
Free cash flow
$
244,833
$
38,610
$
(32,285
)
$
251,158
Cash provided by operating activities, DCF and FCF decreased $82.6 million, $85.4 million and $82.4 million, respectively from 2024 to 2025. The discussion by segment is as follows:
•
Mineral Rights Segment: Cash provided by operating activities, DCF and FCF decreased $59.8 million, $62.5 million and $59.5 million, respectively, primarily due to lower metallurgical coal sales prices and volumes during 2025 as compared to the prior year, in addition to cash received from one-time carbon neutral revenues in 2024.
•
Soda Ash Segment: Cash provided by operating activities, DCF and FCF each decreased $30.9 million prima rily due to lower cash distributions received from Sisecam Wyoming in 2025 as compared to 2024.
•
Corporate and Financing Segment: Operating cash flow, DCF and FCF each improved $8.1 million primarily due to lower cash paid for interest resulting from lower borrowings outstanding on the Opco Credit Facility during the year ended December 31, 2025.
For discussion of our Results of Operations comparing 2024 to 2023, refer to our 2024 Annual Report on Form 10-K filed February 28, 2025 under Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. "
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Liquidity and Capital Resources
Current Liquidity
As of December 31, 2025, we had total liquidity of $211.2 million, consisting of $30.1 million of cash and cash equivalents and $181.1 million of borrowing capacity under our Opco Credit Facility. In February 2026, we and Sisecam Wyoming's managing partner agreed to make an additional capital investment into Sisecam Wyoming ($39.2 million for NRP's 49%) to reduce outstanding amounts under Sisecam Wyoming’s bank credit facility and better position it to compete in the current environment. We have debt service obligations, including approximately $14.3 million of principal repayments on Opco’s senior notes in 2026. As of December 31, 2025 our leverage ratio was 0.2x. The following table calculates our leverage ratio:
(In thousands)
For the Year Ended December 31, 2025
Adjusted EBITDA
$
164,106
Debt—at December 31, 2025
$
33,215
Leverage Ratio
0.2x
Cash Flows
Year Ended December 31, 2025 and 2024 Compared
Cash flows provided by operating activities decreased $82.6 million, from $248.5 million during the year ended December 31, 2024, to $165.9 million during the year ended December 31, 2025, primarily due to decreased cash flow within our Mineral Rights and Soda Ash segments, all discussed above, partially offset by lower cash paid for interest by our Corporate and Financing segment.
Cash flows provided by investing activities decreased $2 .7 mil lion, from $7.5 million during the year ended December 31, 2024, to $4.8 million during the year ended December 31, 2025, primarily related to proceeds received in connection with a coal property condemnation in the second quarter of 2024.
Cash flows used in financing activities decreased $66.6 million, from $237.5 million used during the year ended December 31, 2024, to $170.9 million used during the year ended December 31, 2025, primarily due to the following:
•
$71.7 million of cash used for the redemption of the preferred units in 2024;
•
$65.7 million of cash used for the warrant settlements in 2024;
•
$25.2 million less cash used for debt repayments in 2025 as compared to 2024;
•
$15.7 million less cash used for common unit distributions primarily as a result of a lower special distribution paid in 2025 as compared to 2024;
•
$6.4 million of c ash used for preferred unit distributions in 2024; and
•
$3.1 million less cash used for other items, net in 2025 as compared to 2024.
These decreases in cash flow used were partially offset by $121.2 million of lower cash provided by debt borrowings in 2025 as compared to the prior year period.
For discussion of our Cash Flows comparing 2024 to 2023, refer to our 2024 Annual Report on Form 10-K filed February 28, 2025 under Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. "
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Capital Resources and Obligations
Debt, Net
We had the following debt outstanding as of December 31, 2025 and 2024:
December 31,
(In thousands)
2025
2024
Current portion of debt, net
$
14,198
$
14,192
Long-term debt, net
18,884
127,876
Total debt, net
$
33,082
$
142,068
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, 2025:
Payments Due by Period
Debt Obligations (In thousands)
Total
2026
2027
2028
2029
2030
Thereafter
Opco:
Debt principal payments (including current maturities) (1)
$
33,215
$
14,331
$
—
$
—
$
18,884
$
—
$
—
Debt interest payments (2)
725
725
—
—
—
—
—
Total
$
33,940
$
15,056
$
—
$
—
$
18,884
$
—
$
—
(1)
The amounts indicated in the table include principal due on Opco’s senior notes and credit facility.
(2)
The amounts indicated in the table include interest due on Opco’s senior notes.
Inflation
Despite rising costs during the years ended December 31, 2025, 2024 and 2023, inflation did not have a material impact on operations during any of these years.
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.
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Summary of Critical Accounting Estimates
Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See " Item 8. Financial Statements and Supplementary Data—Note 2. Summary of Significant Accounting Policies " in the audited Consolidated Financial Statements of this Form 10-K for discussion of our significant accounting policies. The following critical accounting policies are affected by estimates and assumptions used in the preparation of Consolidated Financial Statements. We evaluate our estimates and assumptions on a regular basis. Actual results could differ from those estimates.
Revenues
Mineral Rights Segment Revenues
Royalty-based leases. Approximately two-thirds of our royalty-based leases have initial terms of five to 40 years, with substantially all lessees having the option to extend the lease for additional terms. For these types of leases, the lessees generally make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral mined and sold. Most of our coal and aggregates royalty leases require the lessee to pay quarterly or annual minimum amounts, either made in advance or arrears, which are generally recoupable through actual royalty production over certain time periods that generally range from three to five years.
We have defined our coal and aggregates royalty lease performance obligation as providing the lessee the right to mine and sell our coal or aggregates over the lease term. We then evaluated the likelihood that consideration we expected to receive from our lessees resulting from production would exceed consideration expected to be received from minimum payments over the lease term.
As a result of this evaluation, revenue recognition from our royalty-based leases is based on either production or minimum payments as follows:
•
Production Leases : Leases for which we expect that consideration from production will be greater than consideration from minimums over the lease term. Revenue for these leases is recognized over time based on production as royalty revenues, as applicable. Deferred revenue from minimums is recognized as royalty revenues when recoupment occurs or as production lease minimum revenues when the recoupment period expires. In addition, we recognize breakage revenue from minimums when we determine that recoupment is remote. This breakage revenue is included in production lease minimum revenues.
•
Minimum Leases : Leases for which we expect that consideration from minimums will be greater than consideration from production over the lease term. Revenue for these leases is recognized straight-line over the lease term based on the minimum consideration amount as minimum lease straight-line revenues.
This evaluation is performed at the inception of the lease and only reassessed upon modification or renewal of the lease.
Mineral Rights
Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. Coal and aggregates mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimated economic tonnage as estimated by our internal reserve engineers. The technologies and economic data used by our internal reserve engineers in the estimation of our economic tonnage include, but are not limited to, drill logs, geophysical logs, geologic maps including isopach, mine, and coal quality, cross sections, statistical analysis, and available public production data. There are numerous uncertainties inherent in estimating the quantities and qualities of economic tonnage, including many factors beyond our control. Estimates of economically recoverable tonnage depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results.
Asset Impairment
We have developed procedures to evaluate our long-lived assets, including intangible assets, for possible impairment periodically or whenever events or changes in circumstances indicate an asset's net book value may not be recoverable. Potential events or circumstances include, but are not limited to, specific events such as a reduction in economically recoverable tons or production ceasing on a property for an extended period. A long-lived asset is deemed impaired when the future expected undiscounted cash flows from its use and disposition is less than the asset's net book value. Impairment is measured based on the estimated fair value, which is usually determined based upon the present value of the projected future cash flow compared to the asset's net book value. We believe our estimates of cash flows and discount rates are consistent with those of principal market participants.
We evaluate our equity investment for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on quoted market prices, or upon the present value of expected cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate.
Recent Accounting Standards
In November 2024, the FASB issued ASU 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures ("ASU 2024-03"). ASU 2024-03 is intended to improve disclosures about a public business entity's expenses and provide more detailed information to investors about the types of expenses in commonly presented expense captions. The guidance is effective for annual periods beginning after December 15, 2026 and quarterly periods beginning after December 31, 2027 and can be adopted prospectively to financial statements issued for reporting periods after the effective date or retrospectively to all prior periods presented in the financial statements. We are currently evaluating the potential impact of this guidance on our disclosures.
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