ALLIANCE RESOURCE PARTNERS LP 10-K

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ​ ​ Page Report of Independent Registered Public Accounting Firm-Grant Thornton LLP (PCAOB ID Number 248 ) ​ 98 Report of Independent Registered Public Accounting Firm-Ernst & Young LLP (PCAOB ID Number 42 ) ​ 100 Consolidated Balance Sheets ​ 101 Consolidated Statements of Operations ​ 102 Consolidated Statements of Comprehensive Income (Loss) ​ 103 Consolidated Statements of Cash Flows ​ 104 Consolidated Statement of Partners' Capital ​ 105 1. Organization and Presentation ​ 106 2. Summary of Significant Accounting Policies ​ 107 3. Acquisitions ​ 114 4. Long-Lived Asset Impairments ​ 117 5. Goodwill Impairment ​ 117 6. Inventories ​ 118 7. Property, Plant and Equipment ​ 118 8. Long-Term Debt ​ 119 9. Leases ​ 121 10. Fair Value Measurements ​ 122 11. Partners' Capital ​ 123 12. Variable Interest Entities ​ 123 13. Investments ​ 124 14. Revenue From Contracts With Customers ​ 125 15. Earnings Per Limited Partner Unit ​ 126 16. Employee Benefit Plans ​ 126 17. Common Unit-Based Compensation Plans ​ 129 18. Supplemental Cash Flow Information ​ 132 19. Asset Retirement Obligations ​ 132 20. Accrued Workers' Compensation and Pneumoconiosis Benefits ​ 133 21. Related-Party Transactions ​ 136 22. Commitments and Contingencies ​ 137 23. Concentration of Credit Risk and Major Customers ​ 138 24. Segment Information ​ 138 25. Subsequent Events ​ 141 Supplemental Oil & Gas Reserve Information (Unaudited) ​ 142 Schedule I – Condensed Financial Information of Registrant ​ 148 ​ ​ ​ ​ ​ ​ 97 Table of Contents Report of Independent Registered Public Accounting Firm ​ Board of Directors of Alliance Resource Management GP, LLC and Unitholders of Alliance Resource Partners, L.P. ​ Opinion on the Financial Statements We have audited the accompanying consolidated balance sheet of Alliance Resource Partners, L.P. (a Delaware limited partnership) and subsidiaries (the "Partnership") as of December 31, 2021, the related consolidated statements of operations, comprehensive income (loss), cash flows and partners’ capital for the year ended December 31, 2021, and the related notes and financial statement schedule included under Item 15(a)(2) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2021 and the results of its operations and its cash flows for the year ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America. ​ 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, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"), and our report dated February 25, 2022 expressed an unqualified opinion. ​ 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 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 the financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion. ​ Critical Audit 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 critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. ​ Valuation of workers’ compensation and pneumoconiosis benefits ​ As described further in Note 20 to the financial statements, the Partnership provides income replacement and medical treatment for work-related traumatic injury claims and compensation to survivors of workers who suffer employment-related deaths. The Partnership is also liable to pay benefits for black lung disease (or pneumoconiosis) to eligible employees and former employees and their dependents. As of December 31, 2021, the Partnership’s aggregate workers’ compensation and pneumoconiosis benefits obligations were approximately $165 million. We identified valuation of workers’ compensation and pneumoconiosis benefits as a critical audit matter. ​ The principal considerations for assessing the valuation of workers’ compensation and pneumoconiosis benefits as a critical audit matter are the high level of estimation uncertainty related to determining the frequency and severity of these types of claims, as well as the inherent subjectivity in management’s judgment in estimating eligible benefits and the total cost to settle or dispose of these claims. Workers’ compensation and pneumoconiosis benefits obligations are determined using actuarial projection methods and numerous assumptions including claim development patterns, costs, and mortality. The estimates rely on the assumption that historical claim patterns are an accurate representation for future claims. ​ 98 Table of Contents Our audit procedures related to the valuation of workers’ compensation and pneumoconiosis benefits included the following, among others. ​ ● We tested the design and operating effectiveness of controls relating to the workers’ compensation and pneumoconiosis benefits process including testing controls over management’s review of actuarial specialists' liability calculations and the completeness and accuracy of the underlying data. ● We tested management’s process for determining the worker’s compensation and pneumoconiosis benefit accrual, including evaluating the reasonableness of the methods and significant assumptions used in the calculations with the assistance of actuarial specialists. ● We tested the claims data used in the actuarial calculations by inspecting source documents to test key attributes of the claims data. ● We compared claim development patterns and cost assumptions used in the actuarial calculations for consistency with historical experience and current trends. ● We compared the mortality tables used in the actuarial calculations to publicly available information. ​ /s/ GRANT THORNTON LLP ​ We have served as the Partnership’s auditor since 2021. ​ Tulsa, Oklahoma February 25, 2022 ​ 99 Table of Contents Report of Independent Registered Public Accounting Firm ​ To the Board of Directors of Alliance Resource Management GP, LLC and the Partners of Alliance Resource Partners, L.P. ​ Opinion on the Financial Statements We have audited the accompanying consolidated balance sheet of Alliance Resource Partners, L.P. and subsidiaries (the Partnership) as of December 31, 2020, the related consolidated statements of operations, comprehensive income (loss), cash flows and partners’ capital for each of the two years in the period ended December 31, 2020, and the related notes and financial statement schedule listed in the Index at Item 15(a)(2) (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2020, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles. ​ 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 Public Company Accounting Oversight Board (United States) (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 provide a reasonable basis for our opinion. ​ /s/ Ernst & Young LLP ​ We served as the Partnership’s auditor from 2011 to 2021. ​ Tulsa, Oklahoma February 23, 2021, except for Note 24, as to which the date is February 25, 2022 ​ ​ ​ 100 Table of Contents ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES ​ CONSOLIDATED BALANCE SHEETS DECEMBER 31, 2021 AND 2020 (In thousands, except unit data) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2021 2020 ​ ASSETS ​ ​ ​ ​ ​ CURRENT ASSETS: ​ ​ ​ ​ ​ ​ ​ Cash and cash equivalents ​ $ 122,403 ​ $ 55,574 ​ Trade receivables ​ 129,531 ​ 104,579 ​ Other receivables ​ 680 ​ 3,481 ​ Inventories, net ​ 60,302 ​ 56,407 ​ Advance royalties ​ 4,958 ​ 4,168 ​ Prepaid expenses and other assets 21,354 21,565 ​ Total current assets ​ 339,228 ​ 245,774 ​ PROPERTY, PLANT AND EQUIPMENT: ​ ​ ​ ​ ​ ​ ​ Property, plant and equipment, at cost ​ 3,608,347 ​ 3,554,090 ​ Less accumulated depreciation, depletion and amortization ​ ( 1,909,669 ) ​ ( 1,753,845 ) ​ Total property, plant and equipment, net ​ 1,698,678 ​ 1,800,245 ​ OTHER ASSETS: ​ ​ ​ ​ ​ ​ ​ Advance royalties ​ 63,524 ​ 56,791 ​ Equity method investments ​ 26,325 ​ 27,268 ​ Goodwill ​ ​ 4,373 ​ ​ 4,373 ​ Operating lease right-of-use assets ​ ​ 14,158 ​ ​ 15,004 ​ Other long-term assets ​ 13,120 ​ 16,561 ​ Total other assets ​ 121,500 ​ 119,997 ​ TOTAL ASSETS ​ $ 2,159,406 ​ $ 2,166,016 ​ ​ ​ ​ ​ ​ ​ ​ ​ LIABILITIES AND PARTNERS' CAPITAL ​ ​ ​ ​ ​ ​ ​ CURRENT LIABILITIES: ​ ​ ​ ​ ​ ​ ​ Accounts payable ​ $ 69,586 ​ $ 47,511 ​ Accrued taxes other than income taxes ​ 17,787 ​ 25,054 ​ Accrued payroll and related expenses ​ 36,805 ​ 28,524 ​ Accrued interest ​ 5,000 ​ 5,132 ​ Workers' compensation and pneumoconiosis benefits ​ 12,293 ​ 10,646 ​ Current finance lease obligations ​ 840 ​ 766 ​ Current operating lease obligations ​ 1,820 ​ 1,854 ​ Other current liabilities ​ 17,375 ​ 21,919 ​ Current maturities, long-term debt, net ​ 16,071 ​ 73,199 ​ Total current liabilities ​ 177,577 ​ 214,605 ​ LONG-TERM LIABILITIES: ​ ​ ​ ​ ​ ​ ​ Long-term debt, excluding current maturities, net ​ 418,942 ​ 519,421 ​ Pneumoconiosis benefits ​ 107,560 ​ 105,068 ​ Accrued pension benefit ​ 25,590 ​ 46,965 ​ Workers' compensation ​ 44,911 ​ 47,521 ​ Asset retirement obligations ​ 123,517 ​ 121,487 ​ Long-term finance lease obligations ​ 618 ​ 1,458 ​ Long-term operating lease obligations ​ 12,366 ​ 13,078 ​ Other liabilities ​ 22,256 ​ 24,146 ​ Total long-term liabilities ​ 755,760 ​ 879,144 ​ Total liabilities ​ 933,337 ​ 1,093,749 ​ ​ ​ ​ ​ ​ ​ ​ ​ COMMITMENTS AND CONTINGENCIES - (Note 22) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ PARTNERS' CAPITAL: ​ ​ ​ ​ ​ ​ ​ ARLP Partners' Capital: ​ ​ ​ ​ ​ ​ ​ Limited Partners - Common Unitholders 127,195,219 units outstanding ​ 1,279,183 ​ 1,148,565 ​ Accumulated other comprehensive loss ​ ( 64,229 ) ​ ( 87,674 ) ​ Total ARLP Partners' Capital ​ 1,214,954 ​ 1,060,891 ​ Noncontrolling interest ​ ​ 11,115 ​ ​ 11,376 ​ Total Partners' Capital ​ ​ 1,226,069 ​ ​ 1,072,267 ​ TOTAL LIABILITIES AND PARTNERS' CAPITAL ​ $ 2,159,406 ​ $ 2,166,016 ​ ​ See notes to consolidated financial statements . ​ 101 Table of Contents ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES ​ CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2021, 2020 AND 2019 (In thousands, except unit and per unit data) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2021 2020 2019 SALES AND OPERATING REVENUES: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Coal sales ​ $ 1,386,923 ​ $ 1,232,272 ​ $ 1,762,442 ​ Oil & gas royalties ​ ​ 74,988 ​ ​ 42,912 ​ ​ 51,735 ​ Transportation revenues ​ 69,607 ​ 21,129 ​ 99,503 ​ Other revenues ​ 38,458 ​ 31,816 ​ 48,040 ​ Total revenues ​ 1,569,976 ​ 1,328,129 ​ 1,961,720 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ EXPENSES: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses (excluding depreciation, depletion and amortization) ​ 943,257 ​ 859,656 ​ 1,182,100 ​ Transportation expenses ​ 69,607 ​ 21,129 ​ 99,503 ​ Outside coal purchases ​ 6,372 ​ — ​ 23,357 ​ General and administrative ​ 70,160 ​ 59,806 ​ 72,997 ​ Depreciation, depletion and amortization ​ 261,377 ​ 313,387 ​ 309,075 ​ Asset impairments ​ — ​ 24,977 ​ 15,190 ​ Goodwill impairment ​ ​ — ​ ​ 132,026 ​ ​ — ​ Total operating expenses ​ 1,350,773 ​ 1,410,981 ​ 1,702,222 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ INCOME (LOSS) FROM OPERATIONS ​ 219,203 ​ ( 82,852 ) ​ 259,498 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest expense (net of interest capitalized of $ 396 , $ 1,325 and $ 1,211 , respectively) ​ ( 39,229 ) ​ ( 45,613 ) ​ ( 45,875 ) ​ Interest income ​ 88 ​ 135 ​ 379 ​ Equity method investment income ​ 2,130 ​ 907 ​ 2,203 ​ Equity securities income ​ ​ — ​ — ​ 12,906 ​ Acquisition gain ​ ​ — ​ ​ — ​ ​ 177,043 ​ Other income (expense) ​ ( 3,020 ) ​ ( 1,593 ) ​ 561 ​ INCOME (LOSS) BEFORE INCOME TAXES ​ 179,172 ​ ( 129,016 ) ​ 406,715 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ INCOME TAX EXPENSE (BENEFIT) ​ 417 ​ 35 ​ ( 211 ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NET INCOME (LOSS) ​ ​ 178,755 ​ ​ ( 129,051 ) ​ ​ 406,926 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST ​ ​ ( 598 ) ​ ​ ( 169 ) ​ ​ ( 7,512 ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NET INCOME (LOSS) ATTRIBUTABLE TO ARLP ​ $ 178,157 ​ $ ( 129,220 ) ​ $ 399,414 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ EARNINGS PER LIMITED PARTNER UNIT - BASIC AND DILUTED ​ $ 1.36 ​ $ ( 1.02 ) ​ $ 3.07 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ WEIGHTED-AVERAGE NUMBER OF UNITS OUTSTANDING – BASIC AND DILUTED ​ 127,195,219 ​ 127,164,659 ​ 128,116,670 ​ ​ See notes to consolidated financial statements. ​ ​ 102 Table of Contents ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES ​ CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) FOR THE YEARS ENDED DECEMBER 31, 2021, 2020 AND 2019 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2021 2020 2019 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NET INCOME (LOSS) ​ $ 178,755 ​ $ ( 129,051 ) ​ $ 406,926 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ OTHER COMPREHENSIVE INCOME (LOSS): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Defined benefit pension plan ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Amortization of prior service cost (1) ​ ​ 186 ​ ​ 186 ​ ​ 186 ​ Net actuarial gain (loss) ​ 14,921 ​ ( 5,522 ) ​ ( 7,350 ) ​ Amortization of net actuarial loss (1) ​ 4,327 ​ 4,128 ​ 3,922 ​ Total defined benefit pension plan adjustments ​ 19,434 ​ ( 1,208 ) ​ ( 3,242 ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Pneumoconiosis benefits ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net actuarial loss ​ ( 161 ) ​ ( 7,787 ) ​ ( 23,298 ) ​ Amortization of net actuarial loss (gain) (1) ​ 4,172 ​ ( 686 ) ​ ( 4,582 ) ​ Total pneumoconiosis benefits adjustments ​ 4,011 ​ ( 8,473 ) ​ ( 27,880 ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ OTHER COMPREHENSIVE INCOME (LOSS) ​ 23,445 ​ ( 9,681 ) ​ ( 31,122 ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ COMPREHENSIVE INCOME (LOSS) ​ ​ 202,200 ​ ​ ( 138,732 ) ​ ​ 375,804 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Less: Comprehensive income attributable to noncontrolling interest ​ ​ ( 598 ) ​ ​ ( 169 ) ​ ​ ( 7,512 ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO ARLP ​ $ 201,602 ​ $ ( 138,901 ) ​ $ 368,292 ​ (1) Amortization of prior service cost and actuarial gain or loss is included in the computation of net periodic benefit cost (see Notes 16 and 20 for additional details). ​ See notes to consolidated financial statements. ​ ​ ​ 103 Table of Contents ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2021, 2020 AND 2019 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 2020 2019 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ CASH FLOWS FROM OPERATING ACTIVITIES: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) ​ $ 178,755 ​ $ ( 129,051 ) ​ $ 406,926 ​ Adjustments to reconcile net income to net cash provided by operating activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Depreciation, depletion and amortization ​ ​ 261,377 ​ 313,387 ​ 309,075 ​ Non-cash compensation expense ​ 5,709 ​ 3,345 ​ 11,934 ​ Asset retirement obligations ​ 3,688 ​ 4,033 ​ 4,087 ​ Coal inventory adjustment to market ​ 70 ​ 3,245 ​ 4,895 ​ Equity investment income ​ ( 2,130 ) ​ ( 907 ) ​ ( 2,203 ) ​ Distributions from equity method investments ​ ​ 2,130 ​ 907 ​ ​ 2,203 ​ Income from equity securities paid-in-kind ​ ​ — ​ — ​ ​ ( 712 ) ​ Net loss (gain) on sale of property, plant and equipment ​ ( 6,592 ) ​ ( 5,850 ) ​ 109 ​ Asset impairment ​ — ​ 24,977 ​ 15,190 ​ Goodwill impairment ​ ​ — ​ 132,026 ​ — ​ Acquisition gain, net ​ ​ — ​ ​ — ​ ​ ( 177,043 ) ​ Cash received on redemption of equity securities in excess of investment ​ ​ — ​ ​ — ​ ​ ( 11,482 ) ​ Valuation allowance of deferred tax assets ​ ( 834 ) ​ 1,151 ​ ( 413 ) ​ Other ​ 212 ​ 6,631 ​ 5,677 ​ Changes in operating assets and liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Trade receivables ​ ( 24,952 ) ​ 56,172 ​ 20,841 ​ Other receivables ​ 3,109 ​ ( 3,225 ) ​ 3,726 ​ Inventories, net ​ ( 4,673 ) ​ 30,522 ​ ( 35,082 ) ​ Prepaid expenses and other assets ​ 211 ​ ( 2,514 ) ​ 6,136 ​ Advance royalties ​ ( 7,523 ) ​ ( 7,690 ) ​ ( 9,876 ) ​ Accounts payable ​ 19,481 ​ ( 24,282 ) ​ ( 17,671 ) ​ Accrued taxes other than income taxes ​ ( 7,267 ) ​ 9,286 ​ ( 994 ) ​ Accrued payroll and related benefits ​ 8,281 ​ ( 8,051 ) ​ ( 6,538 ) ​ Pneumoconiosis benefits ​ 6,832 ​ 2,340 ​ ( 2,292 ) ​ Workers' compensation ​ ( 1,292 ) ​ 1,355 ​ 3,845 ​ Other ​ ( 9,390 ) ​ ( 7,162 ) ​ ( 15,443 ) ​ Total net adjustments ​ 246,447 ​ 529,696 ​ 107,969 ​ Net cash provided by operating activities ​ 425,202 ​ 400,645 ​ 514,895 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ CASH FLOWS FROM INVESTING ACTIVITIES: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Property, plant and equipment: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Capital expenditures ​ ( 122,984 ) ​ ( 121,101 ) ​ ( 305,858 ) ​ Change in accounts payable and accrued liabilities ​ 2,594 ​ ( 8,773 ) ​ ( 81 ) ​ Proceeds from sale of property, plant and equipment ​ 7,719 ​ 3,762 ​ 1,266 ​ Distributions received from investments in excess of cumulative earnings ​ ​ 943 ​ 988 ​ ​ 2,501 ​ Payments for acquisitions of businesses, net of cash acquired ​ — ​ — ​ ​ ( 320,232 ) ​ Oil & gas reserve acquisition ​ ​ ( 30,960 ) ​ — ​ ​ — ​ Cash received from redemption of equity securities ​ ​ — ​ — ​ ​ 134,288 ​ Net cash used in investing activities ​ ( 142,688 ) ​ ( 125,124 ) ​ ( 488,116 ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ CASH FLOWS FROM FINANCING ACTIVITIES: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Borrowings under securitization facility ​ ​ 35,000 ​ ​ 46,100 ​ ​ 184,500 ​ Payments under securitization facility ​ ​ ( 90,900 ) ​ ​ ( 64,000 ) ​ ( 202,700 ) ​ Proceeds from equipment financings ​ ​ — ​ ​ 14,705 ​ ​ 63,086 ​ Payments on equipment financings ​ ​ ( 17,299 ) ​ ​ ( 14,805 ) ​ ​ ( 2,607 ) ​ Borrowings under revolving credit facilities ​ 15,000 ​ 70,000 ​ 400,000 ​ Payments under revolving credit facilities ​ ( 102,500 ) ​ ( 237,500 ) ​ ( 320,000 ) ​ Borrowings from line of credit ​ ​ 5,340 ​ — ​ — ​ Payment on line of credit ​ ​ ( 5,340 ) ​ — ​ — ​ Payments on finance lease obligations ​ ( 766 ) ​ ( 8,368 ) ​ ( 46,725 ) ​ Payment of debt issuance costs ​ ( 113 ) ​ ( 6,280 ) ​ — ​ Payments for purchases of units under unit repurchase program ​ ​ — ​ — ​ ​ ( 22,892 ) ​ Payments for purchase of units and tax withholdings related to settlements under deferred compensation plans ​ ( 1,090 ) ​ ( 1,310 ) ​ ( 7,817 ) ​ Cash settlement of grants under deferred compensation plan ​ — ​ ( 2,490 ) ​ — ​ Distributions paid to Partners ​ ​ ( 52,158 ) ​ ( 51,753 ) ​ ( 278,425 ) ​ Other ​ ( 859 ) ​ ( 728 ) ​ ( 867 ) ​ Net cash used in financing activities ​ ( 215,685 ) ​ ( 256,429 ) ​ ( 234,447 ) ​ NET CHANGE IN CASH AND CASH EQUIVALENTS ​ 66,829 ​ 19,092 ​ ( 207,668 ) ​ CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ​ 55,574 ​ 36,482 ​ 244,150 ​ CASH AND CASH EQUIVALENTS AT END OF PERIOD ​ $ 122,403 ​ $ 55,574 ​ $ 36,482 ​ See notes to consolidated financial statements. ​ ​ 104 Table of Contents ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL FOR THE YEARS ENDED DECEMBER 31, 2021, 2020 AND 2019 (In thousands, except unit data) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Number of ​ ​ ​ Accumulated ​ ​ ​ ​ ​ ​ ​ ​ ​ Limited ​ ​ ​ Other ​ ​ ​ ​ ​ ​ ​ ​ ​ Partner ​ Limited Partners' ​ Comprehensive ​ Noncontrolling ​ Total Partners' ​ ​ Units Capital Income (Loss) Interest Capital Balance at January 1, 2019 128,095,511 ​ $ 1,229,268 ​ $ ( 46,871 ) ​ $ 5,290 $ 1,187,687 ​ Comprehensive income: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income — ​ 399,414 ​ — ​ ​ 7,512 406,926 ​ Actuarially determined long-term liability adjustments — ​ — ​ ( 31,122 ) ​ — ( 31,122 ) ​ Total comprehensive income ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 375,804 ​ Settlement of deferred compensation plans 596,650 ​ ( 7,817 ) ​ ​ — ​ ​ — ​ ​ ( 7,817 ) ​ Purchase of units under unit repurchase program ​ ( 1,776,564 ) ​ ​ ( 22,892 ) ​ ​ — ​ ​ — ​ ​ ( 22,892 ) ​ Common unit-based compensation — ​ 11,934 ​ ​ — ​ ​ — ​ ​ 11,934 ​ Distributions on deferred common unit-based compensation — ​ ( 3,670 ) ​ ​ — ​ ​ — ​ ​ ( 3,670 ) ​ Distributions from consolidated company to noncontrolling interest ​ — ​ ​ — ​ ​ — ​ ​ ( 867 ) ​ ​ ( 867 ) ​ Distributions to Partners — ​ ​ ( 274,755 ) ​ ​ — ​ ​ — ​ ​ ( 274,755 ) ​ Balance at December 31, 2019 126,915,597 ​ 1,331,482 ​ ( 77,993 ) ​ 11,935 1,265,424 ​ Comprehensive income (loss): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) — ​ ( 129,220 ) ​ — ​ ​ 169 ( 129,051 ) ​ Actuarially determined long-term liability adjustments — ​ — ​ ( 9,681 ) ​ — ( 9,681 ) ​ Total comprehensive loss ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ( 138,732 ) ​ Settlement of deferred compensation plans 279,622 ​ ( 3,800 ) ​ ​ — ​ ​ — ​ ​ ( 3,800 ) ​ Common unit-based compensation — ​ 3,345 ​ ​ — ​ ​ — ​ ​ 3,345 ​ Distributions on deferred common unit-based compensation — ​ ( 986 ) ​ ​ — ​ ​ — ​ ​ ( 986 ) ​ Distributions from consolidated company to noncontrolling interest ​ — ​ ​ — ​ ​ — ​ ​ ( 728 ) ​ ​ ( 728 ) ​ Distributions to Partners — ​ ​ ( 50,767 ) ​ ​ — ​ ​ — ​ ​ ( 50,767 ) ​ Other ​ — ​ ​ ( 1,489 ) ​ ​ — ​ ​ — ​ ​ ( 1,489 ) ​ Balance at December 31, 2020 127,195,219 ​ ​ 1,148,565 ​ ​ ( 87,674 ) ​ ​ 11,376 ​ ​ 1,072,267 ​ Comprehensive income: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income — ​ 178,157 ​ — ​ ​ 598 178,755 ​ Actuarially determined long-term liability adjustments — ​ — ​ 23,445 ​ — 23,445 ​ Total comprehensive income ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 202,200 ​ Settlement of deferred compensation plans — ​ ( 1,090 ) ​ ​ — ​ ​ — ​ ​ ( 1,090 ) ​ Common unit-based compensation — ​ 5,709 ​ ​ — ​ ​ — ​ ​ 5,709 ​ Distributions on deferred common unit-based compensation — ​ ( 1,280 ) ​ ​ — ​ ​ — ​ ​ ( 1,280 ) ​ Distributions from consolidated company to noncontrolling interest ​ — ​ ​ — ​ ​ — ​ ​ ( 859 ) ​ ​ ( 859 ) ​ Distributions to Partners — ​ ​ ( 50,878 ) ​ ​ — ​ ​ — ​ ​ ( 50,878 ) ​ Balance at December 31, 2021 127,195,219 ​ $ 1,279,183 ​ $ ( 64,229 ) ​ $ 11,115 ​ $ 1,226,069 ​ ​ See notes to consolidated financial statements. ​ ​ 105 Table of Contents ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES ​ NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2021, 2020 AND 2019 ​ 1. ORGANIZATION AND PRESENTATION ​ Significant Relationships Referenced in Notes to Consolidated Financial Statements ​ ● References to "we," "us," "our," or "ARLP Partnership" mean the business and operations of Alliance Resource Partners, L.P., the parent company, as well as its consolidated subsidiaries. ● References to "ARLP" mean Alliance Resource Partners, L.P., individually as the parent company, and not on a consolidated basis. ● References to "MGP" mean Alliance Resource Management GP, LLC, ARLP's general partner. ● References to "Mr. Craft" mean Joseph W. Craft III, the Chairman, President and Chief Executive Officer of MGP. ● References to "Intermediate Partnership" mean Alliance Resource Operating Partners, L.P., the intermediate partnership of Alliance Resource Partners, L.P. ● References to "Alliance Coal" mean Alliance Coal, LLC, the holding company for our coal mining operations. ● References to "Alliance Minerals" mean Alliance Minerals, LLC, the holding company for our oil and gas minerals interests. ● References to "Alliance Resource Properties" mean Alliance Resource Properties, LLC, the land holding company for certain of our coal mineral interests, including the subsidiaries of Alliance Resource Properties, LLC. ​ Organization ​ ARLP is a Delaware limited partnership listed on the NASDAQ Global Select Market under the ticker symbol "ARLP." ARLP was formed in May 1999 and completed its initial public offering on August 19, 1999 when it acquired substantially all of the coal production and marketing assets of Alliance Resource Holdings, Inc., a Delaware corporation ("ARH"), and its subsidiaries. We are managed by our general partner, MGP, a Delaware limited liability company which holds a non-economic general partner interest in ARLP. Alliance GP, LLC ("AGP"), which is indirectly wholly owned by Mr. Craft, is the direct owner of MGP. ​ AllDale I & II Acquisition ​ On January 3, 2019 (the "AllDale Acquisition Date"), we acquired all of the limited partner interests not owned by Cavalier Minerals JV, LLC ("Cavalier Minerals") in AllDale Minerals LP ("AllDale I") and AllDale Minerals II, LP ("AllDale II", and collectively with AllDale I, "AllDale I & II") and the general partner interests in AllDale I & II (the "AllDale Acquisition"). As a result of the AllDale Acquisition and our previous investments held through Cavalier Minerals, we acquired control of approximately 43,000 net royalty acres in premier oil & gas resource plays. The AllDale Acquisition provides us with diversified exposure to industry leading operators. ​ Wing Acquisition ​ On August 2, 2019, our subsidiary AR Midland, LP ("AR Midland") acquired from Wing Resources LLC and Wing Resources II LLC (collectively, "Wing") approximately 9,000 net royalty acres in the Midland Basin (the "Wing Acquisition"). The Wing Acquisition enhances our ownership position in the Permian Basin and expands our exposure to industry leading operators. ​ Boulders Acquisition ​ On October 13, 2021, AR Midland acquired approximately 1,480 oil & gas net royalty acres in the Delaware Basin from Boulders Royalty Corp. ("Boulders") for a purchase price of $ 31.0 million (the "Boulders Acquisition"). This acquisition also enhanced our ownership position in the Permian Basin ​ 106 Table of Contents These acquisitions furthered our business strategy to grow our Oil & Gas Royalties segment through accretive acquisitions. See Note 3 – Acquisitions for more information. We now hold approximately 57,000 net royalty acres in premier oil & gas resource plays including our investment in AllDale Minerals III, LP ("AllDale III"). ​ Presentation ​ The consolidated financial statements include the accounts and operations of the ARLP Partnership and present our financial position as of December 31, 2021 and 2020, and results of our operations, comprehensive income, cash flows and changes in partners' capital for each of the three years in the period ended December 31, 2021. All of our intercompany transactions and accounts have been eliminated. ​ 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ​ Consolidation —The consolidated financial statements present the consolidated financial position, results of operations and cash flows of ARLP, the Intermediate Partnership, Alliance Coal and other directly and indirectly wholly- and majority-owned subsidiaries of ARLP. All intercompany transactions and accounts have been eliminated. ​ Variable Interest Entity ("VIE") —VIEs are primarily entities that lack sufficient equity to finance their activities without additional financial support from other parties or whose equity holders, as a group, lack one or more of the following characteristics: (a) direct or indirect ability to make decisions, (b) obligation to absorb expected losses or (c) right to receive expected residual returns. A VIE must be evaluated quantitatively and qualitatively to determine the primary beneficiary, which is the reporting entity that has (a) the power to direct activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE for financial reporting purposes. ​ To determine a VIE's primary beneficiary, we perform a qualitative assessment to determine which party, if any, has the power to direct activities of the VIE and the obligation to absorb losses and/or receive its benefits. This assessment involves identifying the activities that most significantly impact the VIE's economic performance and determine whether it, or another party, has the power to direct those activities. When evaluating whether we are the primary beneficiary of a VIE, we perform a qualitative analysis that considers the design of the VIE, the nature of our involvement and the variable interests held by other parties. See Note 12 – Variable Interest Entities for further information. ​ Estimates —The preparation of consolidated financial statements in conformity with generally accepted accounting principles of the United States ("GAAP") requires management to make estimates and assumptions that affect the reported amounts and disclosures in the consolidated financial statements. Actual results could differ from those estimates. Significant estimates and assumptions include: ​ ● Impairment assessments of investments, property, plant and equipment, and goodwill; ● Asset retirement obligations; ● Pension valuation variables; ● Workers' compensation and pneumoconiosis valuation variables; ● Acquisition related purchase price allocations; ● Life of mine assumptions; ● Oil & gas reserve quantities and carrying amounts; and ● Determination of oil & gas revenue accruals ​ These significant estimates and assumptions are discussed throughout these notes to the consolidated financial statements. ​ Fair Value Measurements —We apply fair value measurements to certain assets and liabilities. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). Valuation 107 Table of Contents techniques used in our fair value measurements are based upon observable and unobservable inputs. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect our own market assumptions. ​ We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels: ​ ● Level 1 – Quoted prices for identical assets and liabilities in active markets that we have the ability to access at the measurement date. ​ ● Level 2 – Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model derived valuations whose inputs are observable or whose significant value drivers are observable. ​ ● Level 3 – Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. ​ The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability. Significant fair value measurements are used in our significant estimates and are discussed throughout these notes. ​ Cash and Cash Equivalents —Cash and cash equivalents include cash on hand and on deposit, including highly liquid investments with maturities of three months or less. ​ Cash Management —The cash flows from operating activities section of our consolidated statements of cash flows reflects immaterial adjustments representing book overdrafts. We did not have material book overdrafts at December 31, 2021, 2020 and 2019. ​ Inventories —Coal inventories are stated at the lower of cost or net realizable value on a first-in, first-out basis. Supply inventories are stated at an average cost basis, less a reserve for obsolete and surplus items. ​ Business Combinations —For acquisitions accounted for as a business combination, we record the assets acquired, including identified intangible assets and liabilities assumed at their fair value, which in many instances involves estimates based on third-party valuations, such as appraisals, or internal valuations based on discounted cash flow analyses or other valuation techniques. ​ Goodwill —Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Goodwill is not amortized, but instead is evaluated for impairment periodically. We evaluate goodwill for impairment annually on November 30th, or more often if events or circumstances indicate that goodwill might be impaired. The reporting unit or units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed or operated. A reporting unit is an operating segment or a component that is one level below an operating segment. During 2020, we recognized an impairment charge of $ 132.0 million consisting of the total carrying amount of goodwill allocated to our Hamilton reporting unit. See Note 5 – Goodwill Impairment for more information. There were no impairments of goodwill during 2021 or 2019. ​ Property, Plant and Equipment —Expenditures which extend the useful lives of existing plant and equipment assets are capitalized. Interest costs associated with major asset additions are capitalized during the construction period. Maintenance and repairs that do not extend the useful life or increase productivity of the asset are charged to operating expense as incurred. Exploration expenditures are charged to operating expense as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves. Land, machinery and equipment under finance lease agreements are capitalized and amortized over the useful lives of the assets given that in each case, ownership transfers at the end of the lease term. Preparation plants, processing facilities and mineral rights, assuming current production estimates, are depreciated or depleted using the units-of-production method over a range from 1 to 29 years . Mining equipment and other plant and equipment assets are depreciated principally using the straight-line method over the estimated useful lives of the assets, ranging from 1 to 29 years , limited by the remaining estimated life of each 108 Table of Contents mine. Depreciable lives for buildings, office equipment and improvements range from 1 to 29 years . Gains or losses arising from retirements are included in operating expenses. Depletion of coal mineral rights is provided on the basis of tonnage mined in relation to estimated recoverable tonnage, which equals estimated proven and probable coal mineral reserves. Therefore, our coal mineral rights are depleted based on only proven and probable coal mineral reserves. See Oil & Gas Reserve Quantities and Carrying Amounts below for a discussion of our accounting policies for oil & gas properties. ​ Mine Development Costs —Mine development costs are capitalized until production, other than production incidental to the mine development process, commences and are amortized on a units of production method based on the estimated proven and probable coal mineral reserves. Mine development costs represent costs incurred in establishing access to coal mineral reserves and include costs associated with sinking or driving shafts and underground drifts, permanent excavations, roads and tunnels. The end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extracted during the development phase is incidental to the mine's production capacity and is not considered to shift the mine into the production phase. ​ Leases —We lease buildings and equipment under operating lease agreements that provide for the payment of minimum rentals. We also have noncancelable lease agreements with third parties for land and equipment under finance lease obligations. Some of our arrangements within these agreements have both lease and non-lease components, which are generally accounted for separately. We have elected a practical expedient to account for lease and non-lease components as a single lease component for leases of buildings and office equipment. Our leases have approximate lease terms of 1 to 29 years , some of which include automatic renewals up to ten years which are likely to be exercised, and some of which include options to terminate the lease within one year . We also hold numerous mineral reserve leases with both related parties as well as third parties, none of which are accounted for as an operating lease or as a finance lease. ​ We review each agreement to determine if an arrangement within the agreement contains a lease at the inception of an arrangement. Once an arrangement is determined to contain either an operating or finance lease with a term greater than 12 months, we recognize a lease liability for the obligation to make lease payments and a right-of-use asset for the right to use the underlying asset for the lease term based on the present value of lease payments over the lease term. The lease term includes all noncancelable periods defined in the lease as well as periods covered by options to extend the lease that we are reasonably certain to exercise. As an implicit borrowing rate cannot be determined under most of our leases, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. ​ Expenses related to leases determined to be operating leases will be recognized on a straight-line basis over the lease term including any reasonably assured renewal periods, while those determined to be finance leases will be recognized following a front-loaded expense profile in which interest and amortization are presented separately in the income statement. The determination of whether a lease is accounted for as a finance lease or an operating lease requires management to make estimates primarily about the fair value of the asset and its estimated economic useful life. ​ Long-Lived Asset Impairment —We review the carrying value of long-lived assets and certain identifiable intangibles whenever events or changes in circumstances indicate that the carrying amount may not be recoverable based upon estimated undiscounted future cash flows. To the extent the carrying amount is not recoverable, the amount of impairment is measured by the difference between the carrying value and the fair value of the asset (See Note 4 – Long-Lived Asset Impairments). ​ Oil & Gas Reserve Quantities and Carrying Amounts —We are wholly dependent on third-party operators to explore, develop, produce and operate the properties associated with our mineral interests. We follow the successful efforts method of accounting for our oil & gas mineral interests. Under this method, costs to acquire mineral interests in oil & gas properties are capitalized when incurred. The costs of mineral interests in unproved properties are capitalized pending the results of exploration and leasing efforts by operators. As mineral interests in unproved properties are determined to be proved, the related costs are transferred to proved oil & gas properties. ​ Mineral interests in oil & gas properties are grouped using a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, which we may also refer to as a depletable group. Mineral interests in proved oil & gas properties are depleted based on the units-of-production method. Proved reserves are quantities of oil & gas that can be estimated with reasonable certainty to be recoverable in the future from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations. Proved developed 109 Table of Contents resources are the quantities expected to be recovered through our operators' existing wells with existing equipment, infrastructure and operating methods. ​ We evaluate impairment of our oil & gas mineral interests in proved properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. This evaluation is performed on a depletable group basis. We compare the undiscounted projected future cash flows expected in connection with a depletable group to its unamortized carrying amount to determine recoverability. When the carrying amount of a depletable group exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, future expenditures, and a risk-adjusted discount rate. ​ Our oil & gas mineral interests in unproved properties are also assessed for impairment periodically but at least annually when facts and circumstances indicate that the unproved property will not be transferred to proved properties. Impairment of individual unproved properties whose acquisition costs are relatively significant are assessed on a property-by-property basis, and an impairment loss is recognized if we determine that the unproved property will not be transferred to proved properties. Impairment of unproved properties whose acquisition costs are not individually significant are assessed on a group basis. Any amount of loss to be recognized and the amount of a valuation allowance needed to provide for impairment of those properties is determined by amortizing those properties in the aggregate on the basis of historical experience and other relevant information, such as the relative proportion of such properties on which proved reserves have been found in the past. ​ Upon the sale of a complete depletable group, the book value thereof, less proceeds or salvage value, are charged to income. Upon the sale or retirement of an aggregation of interests which make up less than a complete depletable group, the proceeds are credited to accumulated depreciation, depletion and amortization, unless doing so would significantly alter the depreciation, depletion and amortization rate of the depletable group, in which case a gain or loss would be recorded. ​ Intangibles —Intangibles subject to amortization include customer contracts acquired from other parties and mining permits. Intangibles other than customer contracts are amortized on a straight-line basis over their useful life. Intangibles for customer contracts are amortized on a per unit basis over the terms of the contracts. Amortization expense attributable to intangibles was $ 3.8 million, $ 4.9 million and $ 9.1 million for the years ending December 31, 2021, 2020 and 2019, respectively. Our intangibles are included in Prepaid expenses and other assets and Other long-term assets on our consolidated balance sheets at December 31, 2021 and 2020. Our intangibles are summarized as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 ​ December 31, 2020 ​ ​ ​ ​ Accumulated Intangibles, ​ ​ Accumulated Intangibles, ​ Original Cost Amortization Net Original Cost Amortization Net ​ ​ (in thousands) ​ Customer contracts and other ​ 10,623 ​ ( 9,504 ) ​ 1,119 ​ 10,623 ​ ( 5,744 ) ​ 4,879 ​ Mining permits ​ 1,500 ​ ( 418 ) ​ 1,082 ​ 1,500 ​ ( 373 ) ​ 1,127 ​ Total ​ $ 12,123 ​ $ ( 9,922 ) ​ $ 2,201 ​ $ 12,123 ​ $ ( 6,117 ) ​ $ 6,006 ​ ​ Amortization expense attributable to intangible assets is estimated as follows: ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ (in thousands) 2022 ​ $ 1,164 ​ 2023 ​ 45 ​ 2024 ​ 45 ​ 2025 ​ 45 ​ 2026 ​ 45 ​ Thereafter ​ 857 ​ ​ Investments —Our investments and ownership interests in equity securities without readily determinable fair values in entities in which we do not have a controlling financial interest or significant influence are accounted for using a measurement alternative other than fair value which is historical cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for identical or similar investments of the same entity. 110 Table of Contents Distributions received on those investments are recorded as income unless those distributions are considered a return on investment, in which case the historical cost is reduced. We accounted for our ownership interests in Kodiak Gas Services, LLC ("Kodiak") as equity securities without readily determinable fair values. In the first quarter of 2019, Kodiak redeemed our preferred interests and therefore Kodiak ceased to be an equity security investment. See Note 13 – Investments for further discussion of this investment. ​ Our investments and ownership interests in entities in which we do not have a controlling financial interest are accounted for under the equity method of accounting if we have the ability to exercise significant influence over the entity. Investments accounted for under the equity method are initially recorded at cost, and the difference between the basis of our investment and the underlying equity in the net assets of the joint venture at the investment date, if any, is amortized over the lives of the related assets that gave rise to the difference. We hold an equity method investment in AllDale III through our subsidiary, Alliance Minerals. See Note 13 – Investments for further discussion of our equity method investment in AllDale III. ​ We review our investments for impairment whenever events or changes in circumstances indicate a loss in the value of the investment may be other-than-temporary. ​ Advance Royalties —Rights to coal mineral leases are often acquired and/or maintained through advance royalty payments. Where royalty payments represent prepayments recoupable against future production, they are recorded as an asset, with amounts expected to be recouped within one year classified as a current asset. As mining occurs on these leases, the royalty prepayments are charged to operating expenses. We assess the recoverability of royalty prepayments based on estimated future production. Royalty prepayments estimated to be nonrecoverable are expensed. Our Advance royalties are summarized as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2021 2020 ​ ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ Advance royalties, affiliates (see Note 21 – Related-Party Transactions) ​ $ 55,613 ​ $ 48,389 ​ Advance royalties, third-parties ​ 12,869 ​ 12,570 ​ Total advance royalties ​ $ 68,482 ​ $ 60,959 ​ ​ Asset Retirement Obligations —Our coal mining operations are governed by various state statutes and the Federal Surface Mining Control and Reclamation Act of 1977, which establish reclamation and mine closing standards. These regulations require, among other things, restoration of property in accordance with specified standards and an approved reclamation plan. We record a liability for the fair value of the estimated cost of future mine asset retirement and closing procedures, escalated for inflation then discounted, on a present value basis in the period incurred or acquired and a corresponding amount is capitalized by increasing the carrying amount of the related long-lived asset. Those costs relate to permanently sealing portals at underground mines and to reclaiming the final pits and support surface acreage for both our underground mines and past surface mines. Examples of these types of costs, common to both types of mining, include, but are not limited to, removing or covering refuse piles and settling ponds, water treatment obligations, and dismantling preparation plants, other facilities and roadway infrastructure. Accounting for asset retirement obligations also requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation is generally determined on a units-of-production basis and accretion is generally recognized over the life of the producing assets. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free interest rate. Federal and state laws require bonds to secure our obligations to reclaim lands used for mining and are typically renewable on a yearly basis. See Note 19 – Asset Retirement Obligations for more information. ​ Pension Benefits —The funded status of our pension benefit plan is recognized separately in our consolidated balance sheets as either an asset or liability. The funded status is the difference between the fair value of plan assets and the plan's benefit obligation. Pension obligations and net periodic benefit costs are actuarially determined and impacted by various assumptions and estimates including expected return on assets, discount rates, mortality assumptions, employee turnover rates and retirement dates. We evaluate our assumptions periodically and make adjustments to these assumptions and the recorded liability as necessary (See Note 16 – Employee Benefit Plans). 111 Table of Contents ​ The discount rate is determined for our pension benefit plan based on an approach specific to our plan. The year end discount rate is determined considering a yield curve comprised of high-quality corporate bonds and the timing of the expected benefit cash flows. ​ The expected long-term rate of return on plan assets is determined based on broad equity and bond indices, the investment goals and objectives, the target investment allocation and on the average annual total return for each asset class. ​ Unrecognized actuarial gains and losses and unrecognized prior service costs and credits are deferred and recorded in accumulated other comprehensive loss until amortized as a component of net periodic benefit cost. Unrecognized actuarial gains and losses in excess of 10 % of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants' average remaining future years of service. ​ Workers ' Compensation and Pneumoconiosis (Black Lung) Benefits —We are liable for workers' compensation benefits for traumatic injuries and benefits for black lung disease (or pneumoconiosis). Both traumatic claims and pneumoconiosis benefits are covered through our self-insured programs. In addition, certain of our mine operating entities are liable under state statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay pneumoconiosis benefits to eligible employees and former employees and their dependents. ​ We provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. Workers' compensation laws also compensate survivors of workers who suffer employment related deaths. Our liability for traumatic injury claims is the estimated present value of current workers' compensation benefits, based on our actuarial estimates. Our actuarial calculations are based on a blend of actuarial projection methods and numerous assumptions including claim development patterns, mortality, medical costs and interest rates. ​ Our pneumoconiosis benefits liability is calculated using the service cost method based on the actuarial present value of the estimated pneumoconiosis obligation. Our actuarial calculations are based on numerous assumptions including claim development patterns, medical costs and mortality. Actuarial gains or losses are amortized over the remaining service period of active miners. See Note 20 – Accrued Workers' Compensation and Pneumoconiosis Benefits for more information on Workers' Compensation and Pneumoconiosis Benefits. ​ Coal Revenue Recognition —Revenues from coal supply contracts with customers, which primarily relate to sales of thermal coal, are recognized at the point in time when control of the coal passes to the customer. We have determined that each ton of coal represents a separate and distinct performance obligation. Our coal supply contracts and other revenue contracts vary in length from short-term to long-term sales contracts and do not typically have significant financing components. Transportation revenues represent the fulfillment costs incurred for the services provided to customers through third-party carriers and for which we are directly reimbursed. Other revenues primarily consist of transloading fees, administrative service revenues from our affiliates, mine safety services and products, other coal contract fees and other handling and service fees. Performance obligations under these contracts are typically satisfied upon transfer of control of the goods or services to our customer which is determined by the contract and could be upon shipment or upon delivery. ​ The estimated transaction price from each of our contracts is based on the total amount of consideration we expect to be entitled to under the contract. Included in the transaction price for certain coal supply contracts is the impact of variable consideration, including quality price adjustments, handling services, government imposition claims, per ton price fluctuations based on certain coal sales price indices and anticipated payments in lieu of shipments. We have constrained the expected value of variable consideration in our estimation of transaction price and only included this consideration to the extent that it is probable that a significant revenue reversal will not occur. The estimated transaction price for each contract is allocated to our performance obligations based on relative standalone selling prices determined at contract inception. Variable consideration is allocated to a specific part of the contract in many instances, such as if the variable consideration is based on production activities for coal delivered during a certain period or the outcome of a customer's ability to accept coal shipments over a certain period. ​ Contract assets are recorded as trade receivables and reported separately in our consolidated balance sheet from other contract assets as title passes to the customer and our right to consideration becomes unconditional. Payments for coal shipments are typically due within two to four weeks of performance. We typically do not have material contract assets that are stated separately from trade receivables as our performance obligations are satisfied as control of the goods or 112 Table of Contents services passes to the customer thereby granting us an unconditional right to receive consideration. Contract liabilities relate to consideration received in advance of the satisfaction of our performance obligations. Contract liabilities are recognized as revenue at the point in time when control of the good or service passes to the customer. ​ Oil & Gas Revenue Recognition —Oil & gas royalty revenues are recognized at the point in time when control of the product is transferred to the purchaser by the lessee and collectability of the sales price is reasonably assured. Oil & gas are priced on the delivery date based upon prevailing market prices with certain adjustments related to oil quality and physical location. The royalty we receive is tied to a market index, with certain adjustments based on, among other factors, whether a well connects to a gathering or transmission line, quality and heat content of the product, and prevailing supply and demand conditions. ​ We also periodically earn revenue from lease bonuses. We recognize lease bonus revenue when we execute a lease of our mineral interests to exploration and production companies. A lease agreement represents our contract with an operator, which is generally an exploration and production company. The contract will (a) generally transfer the rights to any oil or gas discovered, (b) grant us a right to a specified royalty interest from the operator, and (c) require the operator to commence drilling and complete operations within a specified time period. Control of the minerals transfers to the operator when the lease agreement is executed. At the time we execute the lease agreement, we expect to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that we do not adjust the expected amount of consideration for the effects of any significant financing component. ​ As a non-operator, we have limited visibility into the timing of when new wells start producing. In addition, production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices from our properties are estimated and recorded within the Trade receivables line item in our consolidated balance sheets. The difference between our estimates and the actual amounts received for oil & gas royalty revenue are immaterial and recorded in the month that payment is received from the third-party purchaser unless new production information is received prior to the payment allowing us to update the estimate recorded. ​ Common Unit-Based Compensation —We have the Long-Term Incentive Plan ("LTIP") for certain employees and officers of MGP and its affiliates who perform services for us. As part of the LTIP, unit awards of non-vested "phantom" or notional units, also referred to as "restricted units", may be granted which upon satisfaction of time and performance-based vesting requirements, entitle the LTIP participant to receive ARLP common units. Certain awards may also contain a minimum-value guarantee payable in ARLP common units or cash that would be paid regardless of whether or not the awards vest, as long as service requirements are met. Annual grant levels, vesting provisions and minimum-value guarantees of restricted units for designated participants are recommended by Mr. Craft, subject to review and approval of the compensation committee of our general partner ("Compensation Committee"). Vesting of all restricted units outstanding is subject to the satisfaction of certain financial tests. If it is not probable the financial tests for a particular grant of restricted units will be met, any previously expensed amounts for that grant are reversed and no future expense will be recognized for that grant. Assuming the financial tests are met, grants of restricted units issued to LTIP participants are generally expected to cliff vest on January 1st of the third year following issuance of the grants. We expect to settle restricted unit grants by delivery of newly-issued ARLP common units, except for the portion of the grants that will satisfy employee tax withholding obligations of LTIP participants. We account for forfeitures of non-vested LTIP restricted unit grants as they occur. As provided under the distribution equivalent rights ("DERs") provisions of the LTIP and the terms of the LTIP restricted unit awards, all non-vested restricted units include contingent rights to receive quarterly distributions in cash or, at the discretion of the Compensation Committee, phantom units in lieu of cash credited to a bookkeeping account with value equal to the cash distributions we make to unitholders during the vesting period. If it is not probable the financial tests for a particular grant of restricted units will be met, any previously paid DER amounts for that grant are reversed from Partners’ Capital and recorded as compensation expense and any future DERs, for that grant, if any, will be recognized as compensation expense when paid. ​ We utilize the Supplemental Executive Retirement Plan ("SERP") to provide deferred compensation benefits for certain officers and key employees. All allocations made to participants under the SERP are made in the form of "phantom" ARLP units and SERP distributions will be settled in the form of ARLP common units. The SERP is administered by the Compensation Committee. ​ 113 Table of Contents Our directors participate in the MGP Amended and Restated Deferred Compensation Plan for Directors ("Directors' Deferred Compensation Plan"). Pursuant to the Directors' Deferred Compensation Plan, for amounts deferred either automatically or at the election of the director, a notional account is established and credited with notional common units of ARLP, described in the Directors' Deferred Compensation Plan as "phantom" units. Distributions from the Directors' Deferred Compensation Plan will be settled in the form of ARLP common units. ​ For both the SERP and Directors' Deferred Compensation Plan, when quarterly cash distributions are made with respect to ARLP common units, an amount equal to such quarterly distribution is credited to each participant's notional account as additional phantom units. All grants of phantom units under the SERP and Directors' Deferred Compensation Plan vest immediately. ​ The fair value of restricted common unit grants under the LTIP, SERP and the Directors' Deferred Compensation Plan are determined on the grant date of the award and recognized as compensation expense on a pro rata basis for LTIP and SERP awards, as appropriate, over the requisite service period. Compensation expense is fully recognized on the grant date for quarterly distributions credited to SERP accounts and Directors' Deferred Compensation Plan awards. The corresponding liability is classified as equity and included in limited partners' capital in the consolidated financial statements (See Note 17 – Common Unit-Based Compensation Plans). ​ Income Taxes —We are not a taxable entity for federal or state income tax purposes; the tax effect of our activities accrues to the unitholders. Although publicly traded partnerships as a general rule will be taxed as corporations, we qualify for an exemption because at least 90 % of our income consists of qualifying income, as defined in Section 7704(c) of the Internal Revenue Code. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. Individual unitholders have different investment bases depending upon the timing and price of acquisition of their partnership units. Furthermore, each unitholder's tax accounting, which is partially dependent upon the unitholder's tax position, differs from the accounting followed in our consolidated financial statements. Accordingly, the aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder's tax attributes in our partnership is not available to us. We have certain subsidiaries that are subject to federal and state income taxes. These income taxes are not material to our financial position or results of operations. ​ New Accounting Standards Issued and Not Yet Adopted —In November 2021, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2021-10, Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance ("ASU 2021-10"). ASU 2021-10 increases the transparency of government assistance including the disclosure of (1) the types of assistance, (2) an entity’s accounting for the assistance, and (3) the effect of the assistance on an entity’s financial statements. ASU 2021-10 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. The adoption of ASU 2021-10 will not have a material impact on our consolidated financial statements. ​ 3. ACQUISITION S ​ AllDale I & II ​ On the AllDale Acquisition Date, we acquired all of the limited partner interests not owned by Cavalier Minerals in AllDale I & II and the general partner interests in AllDale I & II for $ 176.2 million, which was funded with cash on hand and borrowings under the Revolving Credit Facility. As a result of the AllDale Acquisition and our previous investments held through Cavalier Minerals, we acquired control of approximately 43,000 net royalty acres strategically positioned primarily in the core of the Permian (Delaware and Midland), Anadarko (SCOOP/STACK) and Williston (Bakken) Basins. The AllDale Acquisition provides us with diversified exposure to industry leading operators and is consistent with our general business strategy to grow our Oil & Gas Royalties segment. ​ Because the underlying mineral interests held by AllDale I & II include royalty interests in both developed properties and undeveloped properties, we have determined that the AllDale Acquisition should be accounted for as a business combination and the underlying assets and liabilities of AllDale I & II should be recorded at their AllDale Acquisition Date fair value on our consolidated balance sheet. ​ 114 Table of Contents The final total fair value of the cash paid in the AllDale Acquisition and our previous investments were as follows: ​ ​ ​ ​ ​ ​ ​ As of January 3, 2019 ​ ​ (in thousands) ​ ​ ​ ​ Cash ​ $ 176,205 Previously held investments ​ ​ 307,322 Total ​ $ 483,527 ​ Prior to the AllDale Acquisition Date, we accounted for our investments in AllDale I & II, held through Cavalier Minerals, as equity method investments. The combined fair value of our equity method investments on the AllDale Acquisition Date was $ 307.3 million. We re-measured our equity method investments, which had an aggregate carrying value of $ 130.3 million immediately prior to the AllDale Acquisition. The re-measurement resulted in a gain of $ 177.0 million which is recorded in the Acquisition gain line item in our consolidated statements of income. ​ The following table summarizes the final fair value allocation of assets acquired and liabilities assumed as of the AllDale Acquisition Date: ​ ​ ​ ​ ​ ​ ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ Cash and cash equivalents ​ $ 900 ​ Mineral interests in proved properties ​ ​ 184,032 ​ Mineral interests in unproved properties ​ ​ 291,190 ​ Receivables ​ ​ 9,326 ​ Accounts payable ​ ​ ( 1,921 ) ​ Net assets acquired ​ $ 483,527 ​ ​ Our previous equity method investments in AllDale I & II were held through Cavalier Minerals. Bluegrass Minerals Management, LLC ("Bluegrass Minerals") continues to hold a 4 % membership interest (the "Bluegrass Interest") as well as a profits interest in Cavalier Minerals as it did before the AllDale Acquisition. This Bluegrass Interest represents an indirect noncontrolling interest in AllDale I & II. The AllDale Acquisition Date fair value of the Bluegrass Interest was $ 12.3 million. ​ The fair value of our previous equity method investments, the mineral interests and the Bluegrass Interest were determined using an income approach primarily comprised of discounted cash flow models. The assumptions used in the discounted cash flow models include estimated production, projected cash flows, forward oil & gas prices and a risk adjusted discount rate. Certain assumptions used are not observable in active markets, therefore the fair value measurements represent Level 3 fair value measurements. AllDale I & II's carrying value of the receivables and accounts payable represent their fair value given their short-term nature. ​ The amounts of revenue and earnings, exclusive of the acquisition gain, of AllDale I & II included in our consolidated statements of income from the AllDale Acquisition Date through December 31, 2019 are as follows: ​ ​ ​ ​ ​ ​ Year Ended ​ ​ December 31, ​ ​ 2019 ​ (in thousands) ​ ​ ​ ​ Revenue $ 48,411 ​ Net income 18,543 ​ ​ Wing ​ On August 2, 2019 (the "Wing Acquisition Date"), our subsidiary, AR Midland acquired from Wing approximately 9,000 net royalty acres in the Midland Basin for a cash purchase price of $ 144.9 million. The purchase price was funded with cash on hand and borrowings under our Revolving Credit Facility discussed in Note 8 – Long-Term Debt. The Wing Acquisition enhances our ownership position in the Permian Basin, expands our exposure to industry leading operators 115 Table of Contents and furthers our business strategy to grow our Oil & Gas Royalties segment. Concurrent with the Wing Acquisition, JC Resources LP, an entity owned by Mr. Craft, acquired from Wing, in a separate transaction, mineral interests that we elected not to acquire. ​ Because the mineral interests acquired in the Wing Acquisition include royalty interests in both developed properties and undeveloped properties, we have determined that the acquisition should be accounted for as a business combination and the underlying assets should be recorded at fair value as of the Wing Acquisition Date on our consolidated balance sheet. ​ The following table summarizes our final fair value allocation of assets acquired as of the Wing Acquisition Date: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Mineral interests in proved properties ​ $ 75,071 ​ Mineral interests in unproved properties ​ ​ 67,701 ​ Receivables ​ ​ 2,155 ​ Net assets acquired ​ $ 144,927 ​ ​ The fair value of the mineral interests was determined using a weighting of both income and market approaches. Our income approach primarily comprised a discounted cash flow model. The assumptions used in the discounted cash flow model included estimated production, projected cash flows, forward oil & gas prices and a weighted average cost of capital. Our market approach consisted of the observation of recent acquisitions in the Permian Basin to determine a market price for similar mineral interests. Certain assumptions used in our valuation are not observable in active markets; therefore, the fair value measurements represent Level 3 fair value measurements. The carrying value of the receivables represents the fair value given the short-term nature of the receivables. ​ The amounts of revenue and earnings from the mineral interests acquired in the Wing Acquisition included in our consolidated statements of income from the Wing Acquisition Date through December 31, 2019 are as follows: ​ ​ ​ ​ ​ ​ Year Ended ​ ​ December 31, ​ ​ 2019 ​ (in thousands) ​ ​ ​ ​ Revenue $ 4,625 ​ Net income 1,291 ​ ​ The following represents our actual and pro forma consolidated revenues and net income for the year ended December 31, 2019. Pro forma revenues and net income assumes the mineral interests acquired in the Wing Acquisition had been included in our consolidated results since January 1, 2019. These pro forma amounts have been calculated after applying our accounting policies. ​ ​ ​ ​ ​ ​ ​ ​ Year Ended ​ ​ ​ December 31, ​ ​ 2019 ​ ​ ​ (in thousands) ​ Total revenues ​ ​ ​ ​ As reported ​ $ 1,961,720 ​ Pro forma ​ ​ 1,966,291 ​ ​ ​ ​ ​ ​ Net income ​ ​ ​ ​ As reported ​ $ 406,926 ​ Pro forma ​ ​ 411,217 ​ ​ 116 Table of Contents Boulders ​ On October 13, 2021, AR Midland acquired approximately 1,480 oil & gas net royalty acres in the Delaware Basin from Boulders for a purchase price of $ 31.0 million. This acquisition gives us increased exposure to a prolific area of the Delaware Basin and is within close proximity to reserves acquired in the AllDale and Wing Acquisitions. The acreage is mostly undeveloped. Because more than 90% of the mineral interests acquired in the Boulders Acquisition represent undeveloped properties, including proved undeveloped, we have determined that the Boulders Acquisition should be accounted for as an asset acquisition. We have allocated the purchase price to the acquired reserves as follows: ​ ​ ​ ​ ​ ​ ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Mineral interests in proved properties ​ $ 12,542 ​ Mineral interests in unproved properties ​ ​ 18,419 ​ ​ ​ $ 30,961 ​ ​ ​ 4. LONG-LIVED ASSET IMPAIRMENT S ​ During the year ended December 31, 2020, we recorded $ 23.5 million of non-cash asset impairment charges in our Illinois Basin Coal Operations segment due to sealing our idled Gibson North mine, resulting in its permanent closure, and a decrease in the fair value of certain mining equipment at our idled operations and greenfield coal mineral resources as a result of weakened coal market conditions including the impact of the COVID-19 pandemic. During the same period, we also recorded an asset impairment charge of $ 1.5 million in our Coal Royalties segment due to a decrease in the fair value of greenfield coal mineral resources held by Alliance Resource Properties near our coal mining operations in the Illinois Basin. See Note 24 – Segment Information for more information about our segments. ​ During the year ended December 31, 2019, we recorded asset impairment charges in our Illinois Basin Coal Operations segment and our Coal Royalties segment of $ 7.5 million and $ 7.7 million, respectively, due to the cessation of coal production at our Dotiki mine, effective August 16, 2019, in an effort to focus on maximizing production at our lower-cost mines in the Illinois Basin. We adjusted the carrying value of assets associated with the Dotiki mine, including coal mineral reserves and resources held at Alliance Resource Properties, from $ 35.9 million to their fair value of $ 25.8 million and accrued $ 5.1 million with respect to scheduled payments to WKY CoalPlay, LLC ("WKY CoalPlay") for leased coal mineral reserves and resources from which we may not receive future economic benefit. See Note 12 – Variable Interest Entities for more information about WKY CoalPlay. ​ The fair values of the impaired assets were determined using a market approach, which represents Level 3 fair value measurements under the fair value hierarchy. The fair value analysis used assumptions regarding the marketability of certain mining and coal mineral reserve and resource assets near our Illinois Basin coal mining operations. ​ See Note 2 – Summary of Significant Accounting Policies – Long-Lived Asset Impairment for more information on our accounting policy for asset impairments. ​ 5. GOODWILL IMPAIRMENT ​ During the first quarter of 2020, we considered whether an interim test of our consolidated goodwill of $ 136.4 million was necessary. Our consolidated goodwill included $ 132.0 million recorded in our Illinois Basin Coal Operations segment in conjunction with our acquisition of the Hamilton County Coal, LLC ("Hamilton") mine on July 31, 2015. We assessed certain events and changes in circumstances, including (a) adverse industry and market developments, including the impact of the COVID-19 pandemic, (b) our response to these developments, including temporarily ceasing production at several mines, including our Hamilton mine and (c) our actual performance during the quarter. After consideration of these events and changes in circumstances, we performed an interim test of the goodwill associated with Hamilton comparing Hamilton's carrying amount to its fair value. ​ We estimated the fair value of Hamilton using an income approach utilizing a discounted cash flow model. The assumptions used in the discounted cash flow model included estimated production, forward coal prices, operating expenses, capital expenditures and a weighted average cost of capital. Our forecasts of future cash flows considered market conditions at the time of the assessment and our estimate of the mine's performance in future years based on the 117 Table of Contents information available to us. Key assumptions used in our valuation were not observable in active markets; therefore, the fair value measurements represent Level 3 fair value measurements. The fair value of Hamilton was determined to be below its carrying amount (including goodwill) by more than the recorded balance of goodwill associated with the mine. Accordingly, we recognized an impairment charge of $ 132.0 million consisting of the total carrying amount of goodwill associated with Hamilton. This impairment charge reduced our consolidated goodwill balance to $ 4.4 million. During the first quarter of 2020, we also performed an interim test on our remaining goodwill balances not associated with Hamilton and concluded no impairment was necessary for our other reporting units. ​ 6. INVENTORIES ​ Inventories consist of the following : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2021 2020 ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ Coal ​ $ 24,845 ​ $ 19,756 ​ Supplies (net of reserve for obsolescence of $ 5,554 and $ 5,547 , respectively) ​ 35,457 ​ 36,651 ​ Total inventories, net ​ $ 60,302 ​ $ 56,407 ​ ​ For the year ended December 31, 2020, we recorded lower of cost or net realizable value adjustments of $ 3.2 million to our coal inventories as a result of lower coal sale prices and higher cost per ton due to the impact of lower production on our fixed costs per ton in addition to the impact of challenging market conditions on our production levels. The lower of cost or net realizable value adjustments reflect the impacts of the challenging market conditions and were primarily attributable to the Mettiki and Hamilton mining complexes. ​ See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for inventories. ​ 7. PROPERTY, PLANT AND EQUIPMENT ​ Property, plant and equipment consist of the following: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2021 2020 ​ ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ Mining equipment and processing facilities ​ $ 1,896,470 ​ $ 1,896,324 ​ Land and coal mineral rights ​ 458,440 ​ 454,310 ​ Oil & gas mineral interests ​ ​ 647,864 ​ ​ 616,904 ​ Buildings, office equipment, improvements and other miscellaneous equipment ​ 282,902 ​ 279,938 ​ Construction, mine development and other projects in progress ​ 44,217 ​ 25,799 ​ Mine development costs ​ 278,454 ​ 280,815 ​ Property, plant and equipment, at cost ​ 3,608,347 ​ 3,554,090 ​ Less accumulated depreciation, depletion and amortization ​ ( 1,909,669 ) ​ ( 1,753,845 ) ​ Total property, plant and equipment, net ​ $ 1,698,678 ​ $ 1,800,245 ​ ​ Depreciation, depletion and amortization expense related to property, plant and equipment was $ 256.9 million, $ 297.0 million and $ 312.4 million for the years ended December 31, 2021, 2020 and 2019, respectively. ​ At December 31, 2021 and 2020, land and coal mineral rights above include $ 37.4 million and $ 37.5 million, respectively, of carrying value associated with coal mineral reserves and resources attributable to properties where we or a third party to which we lease coal mineral reserves and resources are not currently engaged in mining operations or leasing to third parties, and therefore, the coal mineral reserves are not currently being depleted. We believe that the carrying value of these coal mineral reserves will be recovered. 118 Table of Contents ​ At December 31, 2021 and 2020, our oil & gas mineral interests noted in the table above includes the carrying value of our unproved oil & gas mineral interests totaling $ 355.1 million and $ 340.5 million, respectively. As discussed in Note 2 – Summary of Significant Accounting Policies, we generally do not record depletion expense for our unproved oil & gas mineral interests; however, we do review for impairment as needed throughout the year. ​ During 2021, we did not incur material mine development costs. During 2020, we incurred $ 13.1 million in mine development costs, primarily related to the development of our Excel Mine No. 5 at our MC Mining complex. All past capitalized mine development costs are associated with other mines that shifted to the production phase in past years and we are amortizing these costs accordingly. We believe that the carrying value of the past development costs will be recovered. ​ See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for property, plant and equipment. ​ 8. LONG-TERM DEBT ​ Long-term debt consists of the following: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Unamortized Discount and ​ ​ ​ Principal ​ Debt Issuance Costs ​ ​ ​ December 31, ​ December 31, ​ ​ 2021 2020 2021 2020 ​ ​ (in thousands) ​ Revolving credit facility ​ $ — ​ $ 87,500 ​ $ ( 5,019 ) ​ $ ( 7,196 ) ​ Senior notes ​ 400,000 ​ 400,000 ​ ( 3,048 ) ​ ( 3,964 ) ​ Securitization facility ​ ​ — ​ ​ 55,900 ​ ​ — ​ ​ — ​ May 2019 equipment financing ​ ​ 1,503 ​ ​ 4,956 ​ ​ — ​ ​ — ​ November 2019 equipment financing ​ ​ 31,972 ​ ​ 42,367 ​ ​ — ​ ​ — ​ June 2020 equipment financing ​ ​ 9,605 ​ ​ 13,057 ​ ​ — ​ ​ — ​ ​ ​ 443,080 ​ 603,780 ​ ( 8,067 ) ​ ( 11,160 ) ​ Less current maturities ​ ( 16,071 ) ​ ( 73,199 ) ​ — ​ — ​ Total long-term debt ​ $ 427,009 ​ $ 530,581 ​ $ ( 8,067 ) ​ $ ( 11,160 ) ​ ​ Credit Facility. On March 9, 2020, our Intermediate Partnership entered into a Fifth Amended and Restated Credit Agreement (the "Credit Agreement") with various financial institutions. The Credit Agreement provides for a $ 459.5 million revolving credit facility, including a sublimit of $ 125 million for the issuance of letters of credit and a sublimit of $ 15.0 million for swingline borrowings (the "Revolving Credit Facility"), with a termination date of March 9, 2024. Concurrently with the entry into the Credit Agreement, we reorganized the entities holding our oil & gas interests such that Alliance Royalty, LLC became a direct wholly owned subsidiary of Alliance Minerals. We incurred debt issuance costs in 2020 of $ 6.3 million in connection with the Credit Agreement. These debt issuance costs are deferred and amortized as a component of interest expense over the term of the Revolving Credit Facility. ​ The Credit Agreement is guaranteed by certain of our Intermediate Partnership's material direct and indirect subsidiaries (the "Restricted Subsidiaries") and is secured by substantially all of the assets of the Restricted Subsidiaries. The Credit Agreement is also guaranteed by Alliance Minerals but the oil and gas minerals assets of Alliance Minerals and its direct and indirect subsidiaries (collectively with Alliance Minerals, the "Unrestricted Subsidiaries") are not collateral under the Credit Agreement. Borrowings under the Revolving Credit Facility bear interest, at our option, at either (i) the Base Rate at the greater of three benchmarks or (ii) a Eurodollar Rate, plus margins for (i) or (ii), as applicable, that fluctuate depending upon the ratio of Consolidated Debt to Consolidated Cash Flow (each as defined in the Credit Agreement). The Eurodollar Rate, with applicable margin, under the Revolving Credit Facility was 2.45 % as of December 31, 2021. At December 31, 2021, we had $ 44.1 million of letters of credit outstanding with $ 415.4 million available for borrowing under the Revolving Credit Facility. We incur an annual commitment fee of 0.35 % on the undrawn portion of the Revolving Credit Facility. We utilize the Revolving Credit Facility, as appropriate, for working capital requirements, capital expenditures and investments, scheduled debt payments and distribution payments. ​ 119 Table of Contents The Credit Agreement contains various restrictions affecting the Intermediate Partnership and its Restricted Subsidiaries including, among other things, restrictions on incurrence of additional indebtedness and liens, sale of assets, investments, mergers and consolidations and transactions with affiliates, including transactions with Unrestricted Subsidiaries. In each case, these restrictions are subject to various exceptions. In addition, the payment of cash distributions is restricted if such payment would result in a fixed charge coverage ratio of less than 1.0 to 1.0 (as defined in the Credit Agreement) for the four most recently ended fiscal quarters. The Credit Agreement requires the Intermediate Partnership to maintain (a) a debt to cash flow ratio of not more than 2.5 to 1.0, (b) a cash flow to interest expense ratio of not less than 3.0 to 1.0 and (c) a first lien debt to cash flow ratio of not more than 1.5 to 1.0, in each case, during the four most recently ended fiscal quarters. The debt to cash flow ratio, cash flow to interest expense ratio and first lien debt to cash flow ratio were 0.95 to 1.0, 11.91 to 1.0 and 0.10 to 1.0, respectively, for the trailing twelve months ended December 31, 2021. We remained in compliance with the covenants of the Credit Agreement as of December 31, 2021 and anticipate remaining in compliance with the covenants. ​ Net restricted assets, as defined by the Securities and Exchange Commission, refers to the amount of our consolidated subsidiaries’ net assets for which the ability to transfer funds to ARLP in the form of cash dividends, loans, advances, or transfers is restricted. As a result of the restrictions contained in the Credit Agreement and our current compliance ratios, the amount of our net restricted assets at December 31, 2021 was $ 372.0 million. ​ Senior Notes. On April 24, 2017, the Intermediate Partnership and Alliance Resource Finance Corporation (as co-issuer), a wholly owned subsidiary of the Intermediate Partnership ("Alliance Finance"), issued an aggregate principal amount of $ 400.0 million of senior unsecured notes due 2025 ("Senior Notes") in a private placement to qualified institutional buyers. The Senior Notes have a term of eight years , maturing on May 1, 2025 (the "Term") and accrue interest at an annual rate of 7.5 %. Interest is payable semi-annually in arrears on each May 1 and November 1. The indenture governing the Senior Notes contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of distributions or similar restricted payments, undertaking transactions with affiliates and limitations on asset sales. The issuers of the Senior Notes may redeem all or a part of the notes at any time at redemption prices set forth in the indenture governing the Senior Notes. ​ Accounts Receivable Securitization . On December 5, 2014, certain direct and indirect wholly owned subsidiaries of our Intermediate Partnership entered into a $ 100.0 million accounts receivable securitization facility ("Securitization Facility"). In January 2021, we reduced the borrowing availability under the facility to $ 60.0 million. Under the Securitization Facility, certain subsidiaries sell certain trade receivables on an ongoing basis to our Intermediate Partnership, which then sells the trade receivables to AROP Funding, LLC ("AROP Funding"), a wholly owned bankruptcy-remote special purpose subsidiary of our Intermediate Partnership, which in turn borrows on a revolving basis up to $ 60.0 million secured by the trade receivables. After the sale, Alliance Coal, as servicer of the assets, collects the receivables on behalf of AROP Funding. The Securitization Facility bears interest based on a Eurodollar Rate. The agreement governing the Securitization Facility contains customary terms and conditions, including limitations with regards to certain customer credit ratings. In January 2022, we extended the term of the Securitization Facility to January 2023. The Securitization Facility was previously scheduled to mature in January 2022. At December 31, 2021, we had no outstanding balance under the Securitization Facility. ​ May 2019 Equipment Financing. On May 17, 2019, the Intermediate Partnership entered into an equipment financing arrangement accounted for as debt, wherein the Intermediate Partnership received $ 10.0 million in exchange for conveying its interest in certain equipment owned indirectly by the Intermediate Partnership and entering into a master lease agreement for that equipment (the "May 2019 Equipment Financing"). The May 2019 Equipment Financing contains customary terms and events of default and provides for thirty-six month ly payments with an implicit interest rate of 6.25 %, maturing on May 1, 2022. Upon maturity, the equipment will revert back to the Intermediate Partnership. ​ November 2019 Equipment Financing. On November 6, 2019, the Intermediate Partnership entered into an equipment financing arrangement accounted for as debt, wherein the Intermediate Partnership received $ 53.1 million in exchange for conveying its interest in certain equipment owned indirectly by the Intermediate Partnership and entering into a master lease agreement for that equipment (the "November 2019 Equipment Financing"). The November 2019 Equipment Financing contains customary terms and events of default and an implicit interest rate of 4.75 %, providing for a four year term with forty-seven monthly payments of $ 1.0 million and a balloon payment of $ 11.6 million upon maturity on November 6, 2023. Upon maturity, the equipment will revert back to the Intermediate Partnership. ​ 120 Table of Contents June 2020 Equipment Financing. On June 5, 2020, the Intermediate Partnership entered into an equipment financing arrangement accounted for as debt, wherein the Intermediate Partnership received $ 14.7 million in exchange for conveying its interest in certain equipment owned indirectly by the Intermediate Partnership and entering into a master lease agreement for that equipment (the "June 2020 Equipment Financing"). The June 2020 Equipment Financing contains customary terms and events of default and provides for forty-eight month ly payments with an implicit interest rate of 6.1 %, maturing on June 5, 2024. Upon maturity, the equipment will revert back to the Intermediate Partnership. ​ Other. We also have an agreement with a bank to provide additional letters of credit in an amount of $ 5.0 million to maintain surety bonds to secure certain asset retirement obligations and our obligations for workers' compensation benefits. At December 31, 2021, we had $ 5.0 million in letters of credit outstanding under this agreement. ​ Aggregate maturities of long-term debt are payable as follows: ​ ​ ​ ​ ​ ​ Year Ended ​ ​ ​ ​ December 31, (in thousands) 2022 ​ $ 16,071 ​ 2023 ​ 24,970 ​ 2024 ​ 2,039 ​ 2025 ​ 400,000 ​ ​ ​ $ 443,080 ​ ​ ​ 9. LEASES ​ The components of lease expense were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2021 ​ 2020 2019 ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance lease cost: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Amortization of right-of-use assets ​ $ 597 ​ $ 704 ​ $ 14,608 ​ Interest on lease liabilities ​ 147 ​ 377 ​ 2,085 ​ Operating lease cost ​ 2,404 ​ 3,873 ​ 9,169 ​ Short-term lease cost ​ ​ 200 ​ ​ 84 ​ ​ 464 ​ Variable lease cost ​ 1,306 ​ 1,375 ​ 1,360 ​ Total lease cost ​ $ 4,654 ​ $ 6,413 ​ $ 27,686 ​ ​ Rental expense was $ 3.3 million, $ 5.2 million and $ 11.0 million for the years ended December 31, 2021, 2020 and 2019 respectively. ​ Supplemental cash flow information related to leases was as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2021 ​ 2020 2019 ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Cash paid for amounts included in the measurement of lease liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating cash flows for operating leases ​ $ 2,367 ​ $ 3,870 ​ $ 9,124 ​ Operating cash flows for finance leases ​ $ 147 ​ $ 377 ​ $ 891 ​ Financing cash flows for finance leases ​ $ 766 ​ $ 8,368 ​ $ 46,725 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Right-of-use assets obtained in exchange for lease obligations: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating leases ​ $ 189 ​ $ 278 ​ $ 25,593 ​ ​ 121 Table of Contents Supplemental balance sheet information related to leases was as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2021 2020 ​ ​ ​ (in thousands) ​ Finance leases: ​ ​ ​ ​ ​ ​ ​ Property and equipment finance lease assets, gross ​ $ 5,485 ​ $ 5,485 ​ Accumulated depreciation ​ ( 4,464 ) ​ ( 3,867 ) ​ Property and equipment finance lease assets, net ​ $ 1,021 ​ $ 1,618 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2021 2020 ​ Weighted average remaining lease term ​ ​ ​ ​ ​ ​ ​ Operating leases ​ ​ 15.5 years ​ ​ 13.4 years ​ Finance leases ​ ​ 3.5 years ​ ​ 3.9 years ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average discount rate ​ ​ ​ ​ ​ ​ ​ Operating leases ​ ​ 6.0 % ​ ​ 6.0 % ​ Finance leases ​ 7.4 % ​ ​ 8.0 % ​ ​ Maturities of lease liabilities as of December 31, 2021 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating leases Finance leases ​ ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 ​ $ 2,257 ​ $ 912 ​ 2023 ​ ​ 2,073 ​ ​ 139 ​ 2024 ​ ​ 1,853 ​ ​ 139 ​ 2025 ​ ​ 1,539 ​ ​ 139 ​ 2026 ​ ​ 1,088 ​ ​ 140 ​ Thereafter ​ ​ 13,284 ​ ​ 140 ​ Total lease payments ​ ​ 22,094 ​ ​ 1,609 ​ Less imputed interest ​ ​ ( 7,908 ) ​ ​ ( 151 ) ​ Total ​ $ 14,186 ​ $ 1,458 ​ ​ ​ 10. FAIR VALUE MEASUREMENTS ​ The following table summarizes our fair value measurements within the hierarchy not included elsewhere in these notes: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 ​ December 31, 2020 ​ ​ Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 ​ ​ (in thousands) ​ Long-term debt ​ $ — ​ $ 457,758 ​ $ — ​ $ — ​ $ 518,317 ​ $ — ​ Total ​ $ — ​ $ 457,758 ​ $ — ​ $ — ​ $ 518,317 ​ $ — ​ ​ See Note 2 – Summary of Significant Accounting Policies – Fair Value Measurements for more information regarding fair value hierarchy levels. ​ The carrying amounts for cash equivalents, accounts receivable, accounts payable, accrued and other liabilities, due from affiliates and due to affiliates approximate fair value due to the short maturity of those instruments. ​ The estimated fair value of our long-term debt, including current maturities, is based on interest rates that we believe are currently available to us in active markets for issuance of debt with similar terms and remaining maturities (See Note 122 Table of Contents 8 – Long-Term Debt). The fair value of debt, which is based upon these interest rates, is classified as a Level 2 measurement under the fair value hierarchy. ​ 11. PARTNERS' CAPITAL ​ Distributions ​ Our available cash that is not used for unit repurchases may, at the discretion of our general partner, be distributed within 45 days after the end of each quarter to unitholders of record. Available cash is generally defined in the partnership agreement as all cash and cash equivalents on hand at the end of each quarter less reserves established by MGP in its reasonable discretion for future cash requirements. These reserves are retained to provide for the conduct of our business, the payment of debt principal and interest and to provide funds for future distributions. The following table summarizes the quarterly per unit distribution paid during each quarter of 2019 through 2021: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2021 2020 2019 First Quarter ​ $ — ​ $ 0.400 ​ $ 0.530 ​ Second Quarter ​ $ 0.100 ​ $ — ​ $ 0.535 ​ Third Quarter ​ $ 0.100 ​ $ — ​ $ 0.540 ​ Fourth Quarter ​ $ 0.200 ​ $ — ​ $ 0.540 ​ ​ On January 28, 2022, we declared a quarterly distribution of $ 0.25 per unit, totaling approximately $ 31.8 million, on all our common units outstanding, which was paid on February 14, 2022, to all unitholders of record on February 7, 2022. ​ Unit Repurchase Program ​ In May 2018, the board of directors of our managing general partner ("Board of Directors") approved the establishment of a unit repurchase program authorizing us to repurchase and retire up to $ 100 million of ARLP common units. The program has no time limit and we may repurchase units from time to time in the open market or in other privately negotiated transactions. The unit repurchase program authorization does not obligate us to repurchase any dollar amount or number of units. No unit repurchases were made during the year ended December 31, 2021. Since inception of the unit repurchase program, we have repurchased and retired 5,460,639 units at an average unit price of $ 17.12 for an aggregate purchase price of $ 93.5 million. ​ Other ​ The noncontrolling interest in our consolidated balance sheets represents Bluegrass Minerals' ownership interest in Cavalier Minerals. Our accumulated other comprehensive loss consists of unrecognized actuarial gains and losses as well as unrecognized prior service costs related to our pension and pneumoconiosis benefits. See Note 12 – Variable Interest Entities, Note 16 –Employee Benefit Plans and Note 20 – Accrued Workers' Compensation and Pneumoconiosis Benefits for further information. ​ 12. VARIABLE INTEREST ENTITIES ​ Cavalier Minerals ​ On November 10, 2014, our subsidiary, Alliance Minerals, and Bluegrass Minerals entered into a limited liability company agreement (the "Cavalier Agreement") to create Cavalier Minerals, which was formed to indirectly acquire oil & gas mineral interests through its ownership in AllDale I & II. Alliance Minerals owns a 96 % member interest in Cavalier Minerals, and Bluegrass Minerals owns a 4 % member interest in Cavalier Minerals and a profits interest which entitles it to receive distributions equal to 25 % of all distributions (including in liquidation) after all members have recovered their investment. Distributions with respect to Bluegrass Minerals' profits interest will be offset by all distributions received by Bluegrass Minerals from the former general partners of AllDale I & II. To date, there has been no profits interest distribution. Bluegrass Minerals was Cavalier Minerals' managing member prior to the AllDale Acquisition (see Note 3 – Acquisitions). In conjunction with the AllDale Acquisition, we became the managing member in Cavalier Minerals. Total contributions to and cumulative distributions from Cavalier Minerals are as follows: 123 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Alliance ​ Bluegrass ​ ​ Minerals ​ Minerals ​ ​ (in thousands) Contributions ​ $ 143,112 ​ $ 5,963 Distributions ​ ​ 109,994 ​ ​ 4,582 ​ We have concluded that Cavalier Minerals is a VIE which we consolidate as the primary beneficiary because we are the managing member and a substantial equity owner in Cavalier Minerals. Bluegrass Minerals' equity ownership of Cavalier Minerals is accounted for as noncontrolling ownership interest in our consolidated balance sheets. In addition, earnings attributable to Bluegrass Minerals are recognized as noncontrolling interest in our consolidated statements of operations. ​ AllDale III ​ In February 2017, Alliance Minerals committed to directly invest $ 30.0 million in AllDale III which was created for similar investment purposes as AllDale I & II. Alliance Minerals completed funding of this commitment in 2018. Alliance Minerals' limited partner interest in AllDale III is 13.9 %. ​ The AllDale III Partnership Agreement includes a 25 % profits interest for the general partner, subject to a return hurdle equal to the greater of 125 % of cumulative capital contributions and a 10 % internal rate of return, and following an 80/20 "catch-up" provision for the general partner. ​ Since AllDale III is structured as a limited partnership with the limited partners 1) not having the ability to remove the general partner and 2) not participating significantly in the operational decisions, we concluded that AllDale III is a VIE. We are not the primary beneficiary of AllDale III as we do not have the power to direct the activities that most significantly impact AllDale III's economic performance. We account for our ownership interest in the income or loss of AllDale III as an equity method investment. We record equity income or loss based on AllDale III's distribution structure. See Note 13 – Investments for more information. ​ See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for variable interest entities. ​ 13. INVESTMENTS ​ AllDale III ​ As discussed in Note 12 – Variable Interest Entities, we account for our ownership interest in the income or loss of AllDale III as an equity method investment. We record equity income or loss based on AllDale III's distribution structure. The changes in our equity method investment in AllDale III for each of the periods presented were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 2020 2019 ​ ​ (in thousands) Beginning balance ​ $ 27,268 ​ $ 28,529 ​ $ 28,974 Equity method investment income ​ ​ 2,130 ​ ​ 907 ​ ​ 2,203 Distributions received ​ ​ ( 3,073 ) ​ ​ ( 1,895 ) ​ ​ ( 2,648 ) Other ​ ​ — ​ ​ ( 273 ) ​ ​ — Ending balance ​ $ 26,325 ​ $ 27,268 ​ $ 28,529 ​ Kodiak ​ On July 19, 2017, Alliance Minerals purchased $ 100 million of Series A-1 Preferred Interests from Kodiak, a privately-held company providing large-scale, high-utilization gas compression assets to customers operating primarily in the Permian Basin. This structured investment provided us with a quarterly cash or payment-in-kind return. On February 8, 2019, Kodiak redeemed our preferred interest for $ 135.0 million in cash resulting in an $ 11.5 million gain due to an early redemption premium. The gain is included in the Equity securities income line item. We no longer hold any 124 Table of Contents ownership interests in Kodiak. Prior to the redemption, we accounted for our ownership interests in Kodiak as equity securities without readily determinable fair values. ​ See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for investments. ​ 14. REVENUE FROM CONTRACTS WITH CUSTOMERS ​ The following table illustrates the disaggregation of our revenues by type, including a reconciliation to our segment presentation as presented in Note 24 – Segment Information. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Coal Operations ​ Royalties ​ Other, ​ ​ ​ ​ ​ ​ Illinois ​ ​ ​ ​ Corporate and ​ ​ ​ ​ Basin Appalachia Oil & Gas Coal Elimination Consolidated ​ ​ ​ (in thousands) ​ Year Ended December 31, 2021 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Coal sales ​ $ 873,930 ​ $ 512,993 ​ $ — ​ $ — ​ $ — ​ $ 1,386,923 ​ Oil & gas royalties ​ ​ — ​ ​ — ​ ​ 74,988 ​ ​ — ​ ​ — ​ ​ 74,988 ​ Coal royalties ​ ​ — ​ ​ — ​ ​ — ​ ​ 51,402 ​ ​ ( 51,402 ) ​ ​ — ​ Transportation revenues ​ ​ 41,001 ​ ​ 28,606 ​ ​ — ​ ​ — ​ ​ — ​ ​ 69,607 ​ Other revenues ​ ​ 4,666 ​ ​ 3,940 ​ ​ 2,197 ​ ​ 69 ​ ​ 27,586 ​ ​ 38,458 ​ Total revenues ​ $ 919,597 ​ $ 545,539 ​ $ 77,185 ​ $ 51,471 ​ $ ( 23,816 ) ​ $ 1,569,976 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2020 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Coal sales ​ $ 755,208 ​ $ 477,064 ​ $ — ​ $ — ​ $ — ​ $ 1,232,272 ​ Oil & gas royalties ​ ​ — ​ ​ — ​ ​ 42,912 ​ ​ — ​ ​ — ​ ​ 42,912 ​ Coal royalties ​ ​ — ​ ​ — ​ ​ — ​ ​ 42,112 ​ ​ ( 42,112 ) ​ ​ — ​ Transportation revenues ​ ​ 12,817 ​ ​ 8,312 ​ ​ — ​ ​ — ​ ​ — ​ ​ 21,129 ​ Other revenues ​ ​ 1,932 ​ ​ 14,954 ​ ​ 229 ​ ​ 105 ​ ​ 14,596 ​ ​ 31,816 ​ Total revenues ​ $ 769,957 ​ $ 500,330 ​ $ 43,141 ​ $ 42,217 ​ $ ( 27,516 ) ​ $ 1,328,129 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2019 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Coal sales ​ $ 1,128,588 ​ $ 628,406 ​ $ — ​ $ — ​ $ 5,448 ​ $ 1,762,442 ​ Oil & gas royalties ​ ​ — ​ ​ — ​ ​ 51,735 ​ ​ — ​ ​ — ​ ​ 51,735 ​ Coal royalties ​ ​ — ​ ​ — ​ ​ — ​ ​ 57,737 ​ ​ ( 57,737 ) ​ ​ — ​ Transportation revenues ​ ​ 94,686 ​ ​ 4,817 ​ ​ — ​ ​ — ​ ​ — ​ ​ 99,503 ​ Other revenues ​ ​ 13,017 ​ ​ 11,166 ​ ​ 1,301 ​ ​ 23 ​ ​ 22,533 ​ ​ 48,040 ​ Total revenues ​ $ 1,236,291 ​ $ 644,389 ​ $ 53,036 ​ $ 57,760 ​ $ ( 29,756 ) ​ $ 1,961,720 ​ ​ The following table illustrates the amount of our transaction price for all current coal supply contracts allocated to performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2021 and disaggregated by segment and contract duration. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2025 and ​ ​ ​ ​ 2022 2023 2024 Thereafter Total ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Illinois Basin Coal Operations coal revenues ​ $ 913,305 ​ $ 321,079 ​ $ 183,189 ​ $ 39,789 ​ $ 1,457,362 ​ Appalachia Coal Operations coal revenues ​ ​ 463,334 ​ ​ 70,595 ​ ​ 49,436 ​ ​ — ​ ​ 583,365 ​ Total coal revenues (1) ​ $ 1,376,639 ​ $ 391,674 ​ $ 232,625 ​ $ 39,789 ​ $ 2,040,727 ​ (1) Coal revenues generally consists of consolidated revenues excluding our Oil & Gas Royalties segment as well as intercompany revenues from our Coal Royalties segment. ​ 125 Table of Contents 15. EARNINGS PER LIMITED PARTNER UNIT ​ We utilize the two-class method in calculating basic and diluted earnings per limited partner unit ("EPU"). Net income attributable to ARLP is allocated to limited partners and participating securities under deferred compensation plans, which include rights to nonforfeitable distributions or distribution equivalents. Net losses attributable to ARLP are allocated to limited partners but not to participating securities. Our participating securities are outstanding restricted unit awards under our LTIP and phantom units in notional accounts under our SERP and the Directors' Deferred Compensation Plan. ​ The following is a reconciliation of net income (loss) attributable to ARLP used for calculating basic and diluted earnings per unit and the weighted-average units used in computing EPU. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 2020 2019 ​ ​ ​ (in thousands, except per unit data) ​ Net income (loss) attributable to ARLP ​ $ 178,157 ​ $ ( 129,220 ) ​ $ 399,414 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Less: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Distributions to participating securities ​ ( 2,334 ) ​ — ​ ( 4,254 ) ​ Undistributed earnings attributable to participating securities ​ ( 2,403 ) ​ — ​ ( 2,237 ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) attributable to ARLP available to limited partners ​ $ 173,420 ​ $ ( 129,220 ) ​ $ 392,923 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted-average limited partner units outstanding – basic and diluted ​ 127,195 ​ 127,165 ​ 128,117 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Earnings per limited partner unit - basic and diluted (1) ​ $ 1.36 ​ $ ( 1.02 ) ​ $ 3.07 ​ (1) Diluted EPU gives effect to all potentially dilutive common units outstanding during the period using the treasury stock method. Diluted EPU excludes all potentially dilutive units calculated under the treasury stock method if their effect is anti-dilutive. For the years ended December 31, 2021, 2020 and 2019, the combined total of LTIP, SERP and Directors' Deferred Compensation Plan units of 1,967,672 , 773,664 and 1,284,013 , respectively, were considered anti-dilutive under the treasury stock method. ​ 16. EMPLOYEE BENEFIT PLANS ​ Defined Contribution Plans —Eligible employees currently participate in a defined contribution profit sharing and savings plan ("PSSP") that we sponsor. The PSSP covers all regular full-time employees. PSSP participants may elect to make voluntary contributions to this plan up to a specified amount of their compensation. We make matching contributions based on a percent of an employee's eligible compensation and also make an additional non-matching contribution. Our contribution expense for the PSSP was approximately $ 17.7 million, $ 16.1 million and $ 21.1 million for the years ended December 31, 2021, 2020 and 2019, respectively. ​ Defined Benefit Plan —Eligible employees and former employees of certain of our mining operations participate in a defined benefit plan (the "Pension Plan") that we sponsor. The Pension Plan is closed to new applicants. Participants in the Pension Plan are no longer receiving benefit accruals for service. Participants can participate in enhanced benefits provisions under the PSSP. The benefit formula for the Pension Plan is a fixed-dollar unit based on years of service. ​ 126 Table of Contents The following sets forth changes in benefit obligations and plan assets for the years ended December 31, 2021 and 2020 and the funded status of the Pension Plan reconciled with the amounts reported in our consolidated financial statements: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2021 2020 ​ ​ (dollars in thousands) ​ Change in benefit obligations: ​ ​ ​ ​ ​ ​ ​ Benefit obligations at beginning of year ​ $ 147,934 ​ $ 136,425 ​ Interest cost ​ 3,438 ​ 4,185 ​ Actuarial loss (gain) ​ ( 6,406 ) ​ 12,396 ​ Benefits paid ​ ( 5,400 ) ​ ( 5,072 ) ​ Benefit obligations at end of year ​ 139,566 ​ 147,934 ​ ​ ​ ​ ​ ​ ​ ​ ​ Change in plan assets: ​ ​ ​ ​ ​ ​ ​ Fair value of plan assets at beginning of year ​ 100,969 ​ 91,567 ​ Employer contribution ​ 3,312 ​ 1,739 ​ Actual return on plan assets ​ 15,095 ​ 12,735 ​ Benefits paid ​ ( 5,400 ) ​ ( 5,072 ) ​ Fair value of plan assets at end of year ​ 113,976 ​ 100,969 ​ Funded status at the end of year ​ $ ( 25,590 ) ​ $ ( 46,965 ) ​ ​ ​ ​ ​ ​ ​ ​ ​ Amounts recognized in balance sheet: ​ ​ ​ ​ ​ ​ ​ Non-current liability ​ $ ( 25,590 ) ​ $ ( 46,965 ) ​ ​ ​ ​ ​ ​ ​ ​ ​ Amounts recognized in accumulated other comprehensive income consists of: ​ ​ ​ ​ ​ ​ ​ Prior service cost ​ $ ( 568 ) ​ $ ( 754 ) ​ Net actuarial loss ​ ​ ( 27,271 ) ​ ​ ( 46,519 ) ​ ​ ​ $ ( 27,839 ) ​ $ ( 47,273 ) ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted-average assumption to determine benefit obligations as of December 31, ​ ​ ​ ​ ​ ​ ​ Discount rate ​ 2.73 % ​ 2.37 % ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted-average assumptions used to determine net periodic benefit cost for the year ended December 31, ​ ​ ​ ​ ​ ​ ​ Discount rate ​ 2.37 % ​ 3.15 % ​ Expected return on plan assets ​ 6.50 % ​ 6.50 % ​ ​ The actuarial gain component of the change in benefit obligations in 2021 was primarily attributable to an increase in the discount rate compared to December 31, 2020. The actuarial loss component of the change in benefit obligations in 2020 was primarily attributable to a decrease in the discount rate compared to December 31, 2019, offset in part by updated mortality tables. ​ The expected long-term rate of return used to determine our pension liability is based on a 1.5 % active management premium in addition to an asset allocation assumption of: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Asset allocation ​ As of December 31, 2021 assumption Equity securities ​ 62 % ​ Fixed income securities 33 % ​ Real estate 5 % ​ ​ 100 % ​ ​ 127 Table of Contents The actual return on plan assets was 15.1 % and 14.2 % for the years ended December 31, 2021 and 2020, respectively. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2021 2020 2019 ​ ​ ​ (in thousands) Components of net periodic benefit cost: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest cost ​ $ 3,438 ​ $ 4,185 ​ $ 4,864 ​ Expected return on plan assets ​ ( 6,580 ) ​ ( 5,861 ) ​ ( 4,932 ) ​ Amortization of prior service cost ​ ​ 186 ​ ​ 186 ​ ​ 186 ​ Amortization of net loss ​ 4,327 ​ 4,128 ​ 3,922 ​ Net periodic benefit cost (1) ​ $ 1,371 ​ $ 2,638 ​ $ 4,040 ​ (1) Nonservice components of net periodic benefit cost are included in the Other income (expense) line item within our consolidated statements of income. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 2020 ​ ​ ​ (in thousands) ​ Other changes in plan assets and benefit obligation recognized in accumulated other comprehensive loss: ​ ​ ​ ​ ​ ​ ​ Net actuarial gain (loss) ​ $ 14,921 ​ $ ( 5,522 ) ​ Reversal of amortization item: ​ ​ ​ ​ ​ ​ ​ Prior service cost ​ ​ 186 ​ ​ 186 ​ Net actuarial loss ​ 4,327 ​ 4,128 ​ Total recognized in accumulated other comprehensive loss ​ 19,434 ​ ( 1,208 ) ​ Net periodic benefit cost ​ ( 1,371 ) ​ ( 2,638 ) ​ Total recognized in net periodic benefit cost and accumulated other comprehensive loss ​ $ 18,063 ​ $ ( 3,846 ) ​ ​ Estimated future benefit payments as of December 31, 2021 are as follows: ​ ​ ​ ​ ​ ​ Year Ended ​ ​ ​ ​ December 31, (in thousands) ​ ​ ​ ​ ​ 2022 ​ $ 5,938 ​ 2023 ​ 6,190 ​ 2024 ​ 6,407 ​ 2025 ​ 6,591 ​ 2026 ​ 6,733 ​ 2027-2031 ​ 34,859 ​ ​ ​ $ 66,718 ​ ​ As a result of certain pension plan contribution relief provided by the American Rescue Plan Act enacted in March 2021, we do no t expect to make contributions to the Pension Plan during 2022. ​ The Compensation Committee has appointed an investment manager with full investment authority with respect to Pension Plan investments subject to investment guidelines and compliance with Employee Retirement Income Security Act of 1974 or other applicable laws. The investment manager employs a series of asset allocation strategy phases to glide the portfolio risk commensurate with both plan characteristics and market conditions. The objective of the allocation policy is to reach and maintain fully funded status. The total portfolio allocation will be adjusted as the funded ratio of the Pension Plan changes and market conditions warrant. Total account performance is reviewed at least annually, using 128 Table of Contents a dynamic benchmark approach to track investment performance. General asset allocation guidelines at December 31, 2021 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Percentage of Total Portfolio ​ Minimum Target Maximum ​ ​ ​ ​ ​ ​ ​ ​ Equity securities ​ 45 % ​ 62 % ​ 80 % ​ Fixed income securities ​ 10 % ​ 33 % ​ 55 % ​ Real estate ​ 0 % ​ 5 % ​ 10 % ​ ​ Equity securities include domestic equity securities, developed international securities, emerging markets equity securities and real estate investment trust. Fixed income securities include domestic and international investment grade fixed income securities, high yield securities and emerging markets fixed income securities. Fixed income futures may also be utilized within the fixed income securities asset allocation. ​ The following information discloses the fair values of our Pension Plan assets by asset category: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2021 ​ 2020 ​ ​ ​ (in thousands) Cash and cash equivalents (a) ​ $ 4,426 ​ $ 3,888 ​ ​ ​ ​ ​ ​ ​ ​ ​ Commingled investment funds measured at net asset value (b): ​ ​ ​ ​ ​ ​ ​ Equities - Global ​ ​ 24,868 ​ ​ 17,549 ​ Equities - United States ​ ​ 41,140 ​ ​ 31,835 ​ Equities - United States futures ​ ​ ( 2,055 ) ​ ​ ( 2,616 ) ​ Equities - International developed markets ​ ​ 16,382 ​ ​ 8,920 ​ Equities - International developed markets futures ​ ​ ( 16,260 ) ​ ​ ( 4,921 ) ​ Equities - International emerging markets ​ ​ ( 3,363 ) ​ ​ 6,600 ​ Equities - International emerging markets futures ​ ​ 7,024 ​ ​ ( 975 ) ​ Fixed income - Investment grade ​ ​ 27,095 ​ ​ 25,703 ​ Fixed income - High yield ​ ​ 177 ​ ​ 10,056 ​ Fixed income - Emerging markets ​ ​ — ​ ​ 2,664 ​ Fixed income - Futures ​ ​ ( 689 ) ​ ​ ( 1,265 ) ​ Real estate ​ ​ 15,231 ​ ​ 3,531 ​ Total ​ $ 113,976 ​ $ 100,969 ​ (a) Cash and cash equivalents represents a Level 1 fair value measurement. See Note 2 – Summary of Significant Accounting Policies – Fair Value Measurements for more information regarding the definitions of fair value hierarchy levels. (b) Investments measured at fair value using the net asset value per share (or its equivalent) have not been classified within the fair value hierarchy. The fair values of all commingled investment funds are determined based on the net asset values per unit of each of the funds. The net asset values per unit represent the aggregate value of the fund's assets at fair value less liabilities, divided by the number of units outstanding. ​ See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for pension benefits. ​ 17. COMMON UNIT-BASED COMPENSATION PLANS ​ Long-Term Incentive Plan ​ We maintain the LTIP for certain employees and officers of MGP and its affiliates who perform services for us. As part of our LTIP, unit awards of non-vested "phantom" or notional units, also referred to as "restricted units", may be granted which upon satisfaction of time and performance-based vesting requirements, entitle the LTIP participant to receive ARLP common units. Certain awards may also contain a minimum-value guarantee payable in ARLP common units or cash that would be paid regardless of whether or not the awards vest, as long as service requirements are met. 129 Table of Contents Annual grant levels, vesting provisions and minimum-value guarantees of restricted units for designated participants are recommended by Mr. Craft, subject to review and approval of the Compensation Committee. Vesting of all restricted units outstanding is subject to the satisfaction of certain financial tests. If it is not probable the financial tests for a particular grant of restricted units will be met, any previously expensed amounts for that grant are reversed and no future expense will be recognized for that grant. Assuming the financial tests are met, grants of restricted units issued to LTIP participants are generally expected to cliff vest on January 1st of the third year following issuance of the grants. We expect to settle restricted unit grants by delivery of newly-issued ARLP common units, except for the portion of the grants that will satisfy employee tax withholding obligations of LTIP participants. We account for forfeitures of non-vested LTIP restricted unit grants as they occur. As provided under the DERs provisions of the LTIP and the terms of the LTIP restricted unit awards, all non-vested restricted units include contingent rights to receive quarterly distributions in cash or, at the discretion of the Compensation Committee, phantom units in lieu of cash credited to a bookkeeping account with value equal to the cash distributions we make to unitholders during the vesting period. If it is not probable the financial tests for a particular grant of restricted units will be met, any previously paid DER amounts for that grant are reversed from Partners’ Capital and recorded as compensation expense and any future DERs, for that grant, if any, will be recognized as compensation expense when paid. ​ A summary of non-vested LTIP grants of restricted units is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Number of units Weighted average grant date fair value per unit Intrinsic value ​ ​ ​ ​ ​ ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Non-vested grants at January 1, 2019 ​ 1,828,080 ​ $ 17.18 ​ $ 31,699 ​ Granted ​ 682,155 ​ ​ 18.63 ​ ​ ​ ​ Vested (1) ​ ( 885,381 ) ​ 12.38 ​ ​ ​ ​ Forfeited ​ ( 21,476 ) ​ 20.84 ​ ​ ​ ​ Non-vested grants at December 31, 2019 ​ 1,603,378 ​ ​ 20.39 ​ ​ 17,349 ​ Granted (2) ​ 1,430,489 ​ ​ 5.02 ​ ​ ​ ​ Vested (3) ​ ( 919,524 ) ​ ​ 21.70 ​ ​ ​ ​ Grants canceled (4) ​ ( 675,302 ) ​ 18.62 ​ ​ ​ ​ Forfeited ​ ( 8,552 ) ​ 20.16 ​ ​ ​ ​ Non-vested grants at December 31, 2020 ​ 1,430,489 ​ ​ 5.02 ​ ​ 6,409 ​ Granted (5) 1,818,190 ​ ​ 6.03 ​ ​ ​ ​ Forfeited ( 118,204 ) ​ 5.48 ​ ​ ​ ​ Non-vested grants at December 31, 2021 3,130,475 ​ 5.59 ​ ​ 39,569 ​ (1) During the year ended December 31, 2019, we issued 596,650 unrestricted common units to LTIP participants. The remaining vested units were settled in cash to satisfy tax withholding obligations of the LTIP participants. (2) In December 2020, we modified the vesting requirements for certain restricted units that we granted in February 2020 which were determined to be improbable of vesting under the original vesting requirements (the "2020 Grants"). The new vesting requirements make it probable the modified restricted units will vest. Also in December 2020, an additional 578,114 restricted units under these modified vesting requirements were granted. The grant date fair value reflects the modification date fair value for those awards that were modified. (3) In February 2020, we issued 279,622 unrestricted common units to LTIP participants as a result of satisfying the vesting requirements for 424,486 restricted units that were granted in 2017. The remaining vested units were settled in cash to satisfy tax withholding obligations of the LTIP participants. In December 2020, we accelerated the vesting requirements for 495,038 restricted units that were granted in 2018 (the "2018 Grants") and settled these restricted units in cash. (4) In December 2020, 675,302 restricted units that were granted in 2019 (the "2019 Grants") were canceled since it was determined that the vesting requirements for these restricted units were not probable of being satisfied. (5) In April 2021, we granted 921,430 restricted units and 896,760 restricted units that have minimum-value guarantees of $ 2.53 per unit and $ 3.79 per unit, respectively, regardless of whether or not the awards vest. ​ For the years ended December 31, 2021, 2020 and 2019, our LTIP expense for grants of restricted units was $ 5.4 million, $ 8.1 million and $ 10.4 million, respectively. LTIP expense for grants of restricted units for the year ended December 31, 2020 includes the impact of the reversal of the 2019 Grants, the modification of the 2020 Grants and 130 Table of Contents incremental compensation cost associated with the cash settlement of the 2018 Grants. The cash settlement of the 2018 Grants was the first time we have settled restricted units in cash and we currently do not expect to do so again in the future. The cash settlement of the 2018 Grants resulted in $ 5.4 million in incremental compensation cost. The 2019 Grants were determined to be not probable of vesting therefore $ 4.8 million of cumulative previously recognized expense was reversed in 2020, offset in part by related DERs for the 2019 Grants previously recorded to equity and then expensed in 2020. The 2020 Grants were determined to be improbable of vesting therefore the Compensation Committee modified the awards to change the vesting requirement, which made the grants probable of vesting, and granted additional restricted units under these modified vesting requirements as previously discussed. As a result, the grant date fair value of the modified awards was changed to reflect the modification date fair value of the awards resulting in a net reduction in LTIP expense of $ 1.0 million for the year ended December 31, 2020. ​ The total obligation associated with LTIP grants of restricted units as of December 31, 2021 and 2020 was $ 6.7 million and $ 1.3 million, respectively, and is included in the partners' capital Limited partners-common unitholders line item in our consolidated balance sheets. As of December 31, 2021, there was $ 10.8 million in total unrecognized compensation expense related to the non-vested LTIP restricted unit grants that are expected to vest. That expense is expected to be recognized over a weighted-average period of 1.6 years. ​ On January 26, 2022, the Compensation Committee authorized additional grants of 694,919 restricted units, of which 687,719 units were granted. These restricted units have minimum-value guarantees of either $ 9.62 or $ 6.41 per unit, regardless of whether or not the awards vest. ​ Supplemental Executive Retirement Plan and Directors' Deferred Compensation Plan ​ We utilize the SERP to provide deferred compensation benefits for certain officers and key employees. All allocations made to participants under the SERP are made in the form of "phantom" ARLP units and SERP distributions will be settled in the form of ARLP common units. The SERP is administered by the Compensation Committee. ​ Our directors participate in the Directors' Deferred Compensation Plan. Pursuant to the Directors' Deferred Compensation Plan, for amounts deferred either automatically or at the election of the director, a notional account is established and credited with notional common units of ARLP, described in the Directors' Deferred Compensation Plan as "phantom" units. Distributions from the Directors' Deferred Compensation Plan will be settled in the form of ARLP common units. ​ For both the SERP and Directors' Deferred Compensation Plan, when quarterly cash distributions are made with respect to ARLP common units, an amount equal to such quarterly distribution is credited to each participant's notional account as additional phantom units. All grants of phantom units under the SERP and Directors' Deferred Compensation Plan vest immediately. ​ 131 Table of Contents A summary of SERP and Directors' Deferred Compensation Plan activity is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Number of units Weighted average grant date fair value per unit Intrinsic value ​ ​ ​ ​ ​ ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Phantom units outstanding as of January 1, 2019 ​ 635,837 ​ $ 27.34 ​ $ 11,025 ​ Granted ​ 111,012 ​ ​ 14.50 ​ ​ ​ ​ Issued (1) ​ ( 115,484 ) ​ ​ 25.20 ​ ​ ​ ​ Phantom units outstanding as of December 31, 2019 ​ 631,365 ​ ​ 25.48 ​ ​ 6,831 ​ Granted ​ 129,265 ​ ​ 5.25 ​ ​ ​ ​ Phantom units outstanding as of December 31, 2020 ​ 760,630 ​ ​ 22.04 ​ ​ 3,408 ​ Granted ​ 46,638 ​ ​ 9.45 ​ ​ ​ ​ Issued (1) ( 138,570 ) ​ ​ 25.86 ​ ​ ​ ​ Phantom units outstanding as of December 31, 2021 668,698 ​ 20.13 ​ ​ 8,452 ​ (1) During the years ended December 31, 2021 and 2019, we issued ARLP common units that we purchased on the open market of 102,962 and 115,484 , respectively, to participants under the SERP and Directors' Deferred Compensation Plan . Units issued in 2021 were net of units settled in cash to satisfy tax withholding obligations. ​ Total SERP and Directors' Deferred Compensation Plan expense was $ 0.4 million, $ 0.7 million and $ 1.6 million for the years ended December 31, 2021, 2020 and 2019, respectively. As of December 31, 2021 and 2020, the total obligation associated with the SERP and Directors' Deferred Compensation Plan was $ 13.5 million and $ 16.8 million, respectively, and is included in the partners' capital Limited partners-common unitholders line item in our consolidated balance sheets. ​ See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for unit-based compensation. ​ 18. SUPPLEMENTAL CASH FLOW INFORMATION ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2021 2020 2019 ​ ​ (in thousands) ​ Cash Paid For: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest ​ $ 36,402 ​ $ 44,226 ​ $ 43,093 ​ Income taxes ​ $ 11 ​ $ 12 ​ $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Non-Cash Activity: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Accounts payable for purchase of property, plant and equipment ​ $ 8,325 ​ $ 5,731 ​ $ 14,504 ​ Right-of-use assets acquired by operating lease ​ $ 189 ​ ​ 278 ​ ​ 25,593 ​ Market value of common units issued under deferred compensation plans before tax withholding requirements ​ $ 1,082 ​ $ 3,837 ​ $ 17,415 ​ ​ ​ ​ ​ 19. ASSET RETIREMENT OBLIGATIONS ​ The majority of our operations are governed by various state statutes and the Federal Surface Mining Control and Reclamation Act of 1977, which establish reclamation and mine closing standards. These regulations require, among other things, restoration of property in accordance with specified standards and an approved reclamation plan. ​ 132 Table of Contents The following table presents the activity affecting the asset retirement and mine closing liability: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2021 2020 ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ Beginning balance ​ $ 127,898 ​ $ 137,514 ​ Accretion expense ​ 3,688 ​ 4,033 ​ Payments ​ ( 1,383 ) ​ ( 1,769 ) ​ Allocation of liability associated with acquisitions, mine development and change in assumptions ​ 896 ​ ( 11,880 ) ​ Ending balance ​ $ 131,099 ​ $ 127,898 ​ ​ For the year ended December 31, 2021, the allocation of liability associated with acquisition, mine development and change in assumptions was immaterial. ​ For the year ended December 31, 2020, the allocation of liability associated with acquisition, mine development and change in assumptions was a net decrease of $ 11.9 million. This net decrease was attributable to lower cost assumptions and completion of certain reclamation obligations across all operations, permit modifications and extension of projected mine life estimates at certain mines, partially offset by acquisition of property with existing reclamation liabilities. ​ ​ The impact of discounting our estimated cash flows resulted in reducing the accrual for asset retirement obligations by $ 98.3 million and $ 102.1 million at December 31, 2021 and 2020, respectively. Estimated payments of asset retirement obligations as of December 31, 2021 are as follows: ​ ​ ​ ​ ​ ​ Year Ended ​ ​ ​ ​ December 31, (in thousands) ​ ​ ​ ​ ​ 2022 ​ $ 7,582 ​ 2023 ​ 2,232 ​ 2024 ​ 558 ​ 2025 ​ 3,788 ​ 2026 ​ 7,256 ​ Thereafter ​ 208,021 ​ Aggregate undiscounted asset retirement obligations ​ 229,437 ​ Effect of discounting ​ ( 98,338 ) ​ Total asset retirement obligations ​ 131,099 ​ Less: current portion ​ ( 7,582 ) ​ Non-current asset retirement obligations ​ $ 123,517 ​ ​ Federal and state laws require bonds to secure our obligations to reclaim lands used for mining and are typically renewable on a yearly basis. As of December 31, 2021 and 2020, we had approximately $ 173.9 million and $ 171.1 million, respectively, in surety bonds outstanding to secure the performance of our reclamation obligations. ​ See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for asset retirement obligations. ​ 20. ACCRUED WORKERS' COMPENSATION AND PNEUMOCONIOSIS BENEFITS ​ We provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. Workers' compensation laws also compensate survivors of workers who suffer employment related deaths. Certain of our mine operating entities are liable under state statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay benefits for black lung disease (or pneumoconiosis) to eligible employees and former employees and their dependents. Both pneumoconiosis and traumatic claims are covered through our self-insured programs. ​ 133 Table of Contents The following is a reconciliation of the changes in workers' compensation liability (including current and long-term liability balances): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2021 2020 ​ ​ ​ (in thousands) ​ Beginning balance ​ $ 54,739 ​ $ 53,384 ​ Accruals increase ​ 5,168 ​ 5,146 ​ Payments ​ ( 10,725 ) ​ ( 8,482 ) ​ Interest accretion ​ 926 ​ 1,278 ​ Valuation loss ​ 3,340 ​ 3,413 ​ Ending balance ​ $ 53,448 ​ $ 54,739 ​ ​ The discount rate used to calculate the estimated present value of future obligations for workers' compensation was 2.41 % and 1.95 % at December 31, 2021 and 2020, respectively. ​ The valuation loss in 2021 was primarily attributable to unfavorable changes in claims development partially offset by an increase in the discount rate used to calculate the estimated present value of future obligations. The 2020 valuation loss was primarily attributable to a decrease in the discount rate used to calculate the estimated present value of future obligations as well as unfavorable changes in claims development. ​ As of December 31, 2021 and 2020, we had $ 100.4 million and $ 95.2 million, respectively, in surety bonds and letters of credit outstanding to secure workers' compensation obligations. ​ We limit our exposure to traumatic injury claims by purchasing a high deductible insurance policy that starts paying benefits after deductibles for the particular claim year have been met. Our workers' compensation liability above is presented on a gross basis and does not include our expected receivables on our insurance policy. Our receivables for traumatic injury claims under this policy as of December 31, 2021 and 2020 are $ 5.7 million and $ 7.1 million, respectively. Our receivables are included in Other long-term assets on our consolidated balance sheets. ​ The following is a reconciliation of the changes in pneumoconiosis benefit obligations: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2021 2020 ​ ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ Benefit obligations at beginning of year ​ $ 108,496 ​ $ 97,683 ​ Service cost ​ 4,021 ​ 3,526 ​ Interest cost ​ 2,545 ​ 2,998 ​ Actuarial loss ​ 161 ​ 7,787 ​ Benefits and expenses paid ​ ( 3,907 ) ​ ( 3,498 ) ​ Benefit obligations at end of year ​ $ 111,316 ​ $ 108,496 ​ ​ The following is a reconciliation of the changes in the pneumoconiosis benefit obligation recognized in accumulated other comprehensive loss: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 2020 2019 ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net actuarial loss ​ $ ( 161 ) ​ $ ( 7,787 ) ​ $ ( 23,298 ) ​ Reversal of amortization item: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net actuarial loss (gain) ​ 4,172 ​ ( 686 ) ​ ( 4,582 ) ​ Total recognized in accumulated other comprehensive loss ​ $ 4,011 ​ $ ( 8,473 ) ​ $ ( 27,880 ) ​ ​ 134 Table of Contents The discount rate used to calculate the estimated present value of future obligations for pneumoconiosis benefits was 2.73 %, 2.38 % and 3.12 % at December 31, 2021, 2020 and 2019, respectively. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 2020 2019 ​ ​ (in thousands) ​ Amount recognized in accumulated other comprehensive loss consists of: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net actuarial loss ​ $ 36,388 ​ $ 40,399 ​ $ 31,927 ​ ​ The actuarial loss component of the change in benefit obligations in 2021 was primarily attributable to unfavorable assumption changes regarding future medical and legal expense levels. These components were offset in part by a) an increase in the discount rate used to calculate the estimated present value of the future obligations and b) favorable black lung claims experience and other demographic changes in the at-risk population. The actuarial loss component of the change in benefit obligations in 2020 was primarily attributable to a) a decrease in the discount rate used to calculate the estimated present value of the future obligations and b) an increase in the assumptions regarding future medical benefits and legal expenses. These components were partially offset in part by favorable demographic changes in the at-risk population. ​ Summarized below is information about the amounts recognized in the accompanying consolidated balance sheets for pneumoconiosis and workers' compensation benefits: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2021 2020 ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ Workers’ compensation claims ​ $ 53,448 ​ $ 54,739 ​ Pneumoconiosis benefit claims ​ ​ 111,316 ​ ​ 108,496 ​ Total obligations ​ 164,764 ​ 163,235 ​ Less current portion ​ ( 12,293 ) ​ ( 10,646 ) ​ Non-current obligations ​ $ 152,471 ​ $ 152,589 ​ ​ Both the pneumoconiosis benefit and workers' compensation obligations were unfunded at December 31, 2021 and 2020. ​ The pneumoconiosis benefit and workers' compensation expense consists of the following components: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2021 2020 2019 ​ ​ ​ (in thousands) ​ Black lung benefits: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Service cost $ 4,021 ​ $ 3,526 ​ $ 2,593 ​ Interest cost (1) ​ 2,545 ​ 2,998 ​ 3,044 ​ Net amortization (1) ​ 4,172 ​ ( 686 ) ​ ( 4,582 ) ​ Total pneumoconiosis expense ​ 10,738 ​ 5,838 ​ 1,055 ​ Workers' compensation expense ​ 8,339 ​ 12,305 ​ 17,541 ​ Net periodic benefit cost ​ $ 19,077 ​ $ 18,143 ​ $ 18,596 ​ ________________________________________ (1) Interest cost and net amortization is included in the Other income (expense) line item within our consolidated statements of income ( see Note 2 – Summary of Significant Accounting Policies). ​ See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for workers' compensation and pneumoconiosis benefits. ​ 135 Table of Contents 21. RELATED-PARTY TRANSACTIONS ​ We have continuing related-party transactions with MGP and its affiliates. The Board of Directors and its conflicts committee ("Conflicts Committee") review our related-party transactions that involve a potential conflict of interest between our general partner or its affiliates and ARLP or its subsidiaries or any other partner of ARLP to determine that such transactions are fair and reasonable to ARLP. As a result of these reviews, the Board of Directors and the Conflicts Committee approved each of the transactions described below that had such potential conflict of interest as fair and reasonable to ARLP. ​ Line of Credit ​ On February 19, 2021, we entered into a line of credit arrangement (the "Line of Credit") with a related party for $ 5.0 million. This Line of Credit was amended on November 4, 2021 to increase the total available under the Line of Credit to $ 5.5 million. The Line of Credit had a maturity date of February 28, 2023 and accrued interest at an annual rate of 3.5 % payable quarterly. During the year ended December 31, 2021 we received proceeds and made payments under the Line of Credit of $ 5.3 million. On November 10, 2021 we terminated the Line of Credit. ​ Affiliate Coal Lease Agreements ​ The following table summarizes advanced royalties outstanding and related payments and recoupments under our affiliate coal lease agreements: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ WKY CoalPlay ​ ​ ​ ​ ​ ​ ​ Towhead ​ Webster ​ Henderson ​ WKY ​ ​ ​ ​ ​ Craft Foundations ​ Coal ​ Coal ​ Coal ​ CoalPlay ​ ​ ​ ​ ​ ​ ​ Henderson ​ ​ ​ ​ ​ Henderson ​ ​ ​ ​ ​ ​ Tunnel ​ & Union ​ Webster ​ Henderson ​ & Union ​ ​ ​ ​ ​ ​ Ridge ​ Counties, KY ​ County, KY ​ County, KY ​ Counties, KY ​ Total ​ ​ ​ Acquired ​ Acquired ​ Acquired ​ Acquired ​ Acquired ​ ​ ​ ​ ​ ​ 2005 ​ December 2014 ​ December 2014 ​ December 2014 ​ February 2015 ​ ​ ​ ​ ​ (in thousands) ​ As of January 1, 2019 ​ $ — ​ $ 14,077 ​ $ — ​ $ 10,086 ​ $ 8,482 ​ $ 32,645 ​ Payments ​ ​ 4,500 ​ ​ 3,597 ​ ​ 2,568 ​ ​ 2,521 ​ ​ 2,131 ​ ​ 15,317 ​ Recoupment ​ ​ ( 3,000 ) ​ ​ ( 1,071 ) ​ ​ — ​ ​ — ​ ​ ( 107 ) ​ ​ ( 4,178 ) ​ Unrecoupable ​ ​ — ​ ​ — ​ ​ ( 2,568 ) ​ ​ — ​ ​ — ​ ​ ( 2,568 ) ​ As of December 31, 2019 ​ ​ 1,500 ​ ​ 16,603 ​ ​ — ​ ​ 12,607 ​ ​ 10,506 ​ ​ 41,216 ​ Payments ​ ​ 3,000 ​ ​ 3,597 ​ ​ 2,568 ​ ​ 2,522 ​ ​ 2,132 ​ ​ 13,819 ​ Recoupment ​ ​ ( 3,000 ) ​ ​ ( 1,022 ) ​ ​ — ​ ​ — ​ ​ ( 56 ) ​ ​ ( 4,078 ) ​ Unrecoupable ​ ​ — ​ ​ — ​ ​ ( 2,568 ) ​ ​ — ​ ​ — ​ ​ ( 2,568 ) ​ As of December 31, 2020 ​ ​ 1,500 ​ ​ 19,178 ​ ​ — ​ ​ 15,129 ​ ​ 12,582 ​ ​ 48,389 ​ Payments ​ ​ 3,000 ​ ​ 3,597 ​ ​ 2,568 ​ ​ 2,521 ​ ​ 2,131 ​ ​ 13,817 ​ Recoupment ​ ​ ( 3,000 ) ​ ​ ( 1,025 ) ​ ​ — ​ ​ — ​ ​ — ​ ​ ( 4,025 ) ​ Unrecoupable ​ ​ — ​ ​ — ​ ​ ( 2,568 ) ​ ​ — ​ ​ — ​ ​ ( 2,568 ) ​ As of December 31, 2021 ​ $ 1,500 ​ $ 21,750 ​ $ — ​ $ 17,650 ​ $ 14,713 ​ $ 55,613 ​ ​ Craft Foundations — In January 2005, we acquired Tunnel Ridge from ARH. In connection with this acquisition, we assumed a coal lease with Alliance Resource GP, LLC, an entity indirectly wholly owned by Mr. Craft and Kathleen S. Craft until it was dissolved in December 2020. In December 2018, the property subject to the lease was transferred to the Joseph W. Craft III Foundation and the Kathleen S. Craft Foundation, which each hold an undivided one - half interest (the "Craft Foundations"). Under the terms of the lease, Tunnel Ridge is required to pay an annual minimum royalty of $ 3.0 million. The lease expires the earlier of January 1, 2033 or upon the exhaustion of the mineable and merchantable leased coal. Tunnel Ridge incurred $ 5.8 million, $ 6.1 million and $ 7.2 million in earned royalties in 2021, 2020 and 2019 respectively. ​ WKY CoalPlay — In February 2015, WKY CoalPlay entered into a coal lease agreement with Alliance Resource Properties regarding coal mineral resources located in Henderson and Union Counties, Kentucky. The lease has an initial term of 20 years and provides for earned royalty payments to WKY CoalPlay of 4.0 % of the coal sales price and annual 136 Table of Contents minimum royalty payments of $ 2.1 million. All annual minimum royalty payments are recoupable from future earned royalties. Alliance Resource Properties also was granted an option to acquire the leased mineral reserves and resources at any time during a three-year period beginning in February 2018 for a purchase price that would provide WKY CoalPlay a 7.0 % internal rate of return on its investment in these coal mineral reserves and resources taking into account payments previously made under the lease. These options expired in February 2021. ​ In December 2014, WKY CoalPlay's subsidiaries, Towhead Coal Reserves, LLC and Henderson Coal Reserves, LLC entered into coal lease agreements with Alliance Resource Properties. The leases have initial terms of 20 years and provide for earned royalty payments of 4.0 % of the coal sales price to both and annual minimum royalty payments of $ 3.6 million and $ 2.5 million, respectively. All annual minimum royalty payments for each agreement are recoupable from future earned royalties related to their respective agreements. Each agreement granted Alliance Resource Properties an option to acquire the leased coal mineral reserves and resources at any time during a three-year period beginning in December 2017 for a purchase price that would provide WKY CoalPlay a 7.0 % internal rate of return on its investment in the coal mineral reserves and resources taking into account payments previously made under the leases. These options expired in December 2020. (See Note 12 – Variable Interest Entities). ​ In December 2014, WKY CoalPlay's subsidiary, Webster Coal Reserves, LLC entered into a coal lease agreement with Alliance Resource Properties. The lease has an initial term of 7 years and provides for earned royalty payments of 4.0 % of the coal sales price and annual minimum payments of $ 2.6 million. The agreement grants Alliance Resource Properties an option to acquire the leased coal mineral resources at any time during a three year period beginning in December 2017 for a purchase price that would provide WKY CoalPlay a 7.0 % internal rate of return on its investment in the coal mineral resources taking into account payments previously made under the lease (See Note 12 – Variable Interest Entities). In the third quarter of 2019 it was determined that the balance of advanced royalties, the advance royalty payment in 2020 and 2021 may not be recouped as a result of the reduction of the Dotiki’s economic mine life determined in 2018 and the subsequent ceasing of production in the third quarter of 2019. We accrued the expected future advance payments and recognized the charge in Asset Impairment expense in the third quarter of 2019. See Note 4 – Long-Lived Asset Impairments for more information. ​ Cavalier Minerals – As discussed in Note 12 – Variable Interest Entities, through our subsidiaries, we hold a non-economic managing member interest and a 96 % non-managing member interest in Cavalier Minerals and, Bluegrass Minerals, a third party, holds a 4 % non-managing member interest and a profits interest. See Note 13 – Investments for information on payments made and distributions received by Cavalier Minerals. ​ 22. COMMITMENTS AND CONTINGENCIES ​ Commitments — We lease buildings and equipment under operating lease agreements that provide for the payment of both minimum and contingent rentals. We also have noncancelable coal mineral reserve and resource leases as discussed in Note 21 – Related-Party Transactions. ​ Contractual Commitments — In connection with planned capital projects, we have contractual commitments of approximately $ 85.7 million at December 31, 2021. As of December 31, 2021, we had no commitments to purchase coal from external production sources in 2021 and thereafter. ​ General Litigation — We are party to litigation that has been initiated against certain of our subsidiaries in which the plaintiffs allege violations of the Fair Labor Standards Act and Kentucky Wage and Hour Act due to an alleged failure to compensate for time "donning" and "doffing" equipment and to account for certain bonuses in the calculation of overtime rates and pay. The plaintiffs seek class or collective action certification. Because the litigation of these matters is in the early stages, we cannot reasonably estimate a range of potential exposure at this time. We believe the plaintiffs’ claims are without merit and our ultimate exposure, if any, will not be material to our results of operations or financial position and we intend to defend the litigation vigorously. However, if our current belief that the claims are without merit is not upheld, it is reasonably possible that the ultimate resolution of these matters could result in a potential loss that may be material to our results of operations. ​ We also have various other lawsuits, claims and regulatory proceedings incidental to our business that are pending against the ARLP Partnership. We record an accrual for a potential loss related to these matters when, in management's opinion, such loss is probable and reasonably estimable. Based on known facts and circumstances, we believe the ultimate outcome of these outstanding lawsuits, claims and regulatory proceedings will not have a material adverse effect on our 137 Table of Contents financial condition, results of operations or liquidity. However, if the results of these matters are different from management's current expectations and in amounts greater than our accruals, such matters could have a material adverse effect on our business and operations. ​ Other —Effective December 1, 2021, we renewed our annual property and casualty insurance program. Our property insurance was procured from our wholly owned captive insurance company, Wildcat Insurance, LLC ("Wildcat Insurance"). Wildcat Insurance charged certain of our subsidiaries for the premiums on this program and in return purchased reinsurance for the program in the standard market. The maximum limit in the commercial property program is $ 100.0 million per occurrence, excluding a $ 1.5 million deductible for property damage, a 75 or 90 day waiting period for underground business interruption depending on the mining complex and an additional $ 10.0 million overall aggregate deductible. We have elected to retain a 10 % participating interest in our commercial property insurance program. We can make no assurances that we will not experience significant insurance claims in the future that could have a material adverse effect on our business, financial condition, results of operations and ability to purchase property insurance in the future. Also, exposures exist for which no insurance may be available and for which we have not reserved. In addition, the insurance industry has been subject to efforts by environmental activists to restrict coverages available for fossil-fuel companies. ​ 23. CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS ​ The international coal market has been a part of our business with indirect sales to end-users in Europe, Africa, Asia, North America and South America. Our sales into the international coal market are considered exports and are made through brokered transactions. During the years ended December 31, 2021, 2020 and 2019, export tons represented approximately 12.5 %, 3.3 % and 17.9 % of tons sold, respectively. ​ Because title to our export shipments typically transfers to our brokerage customers at a point that does not necessarily reflect the end-usage point, we attribute export tons to the country with the end-usage point, if known. No individual country was attributed greater than 10% of total domestic and export tons sold during the years ended December 31, 2021, 2020 and 2019. ​ We have significant long-term coal supply agreements, some of which contain prospective price adjustment provisions designed to reflect changes in market conditions, labor and other production costs and, in the infrequent circumstance when the coal is sold other than free on board the mine, changes in transportation rates. Our major customers are defined as those customers from which we derive at least ten percent of our total revenues, including transportation revenues. Total revenues from major customers are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ Segment 2021 ​ 2020 ​ 2019 ​ ​ ​ ​ (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Customer A Illinois Basin ​ $ 239,482 ​ $ 197,379 ​ $ 228,500 ​ Customer B ​ Appalachia ​ ​ — ​ ​ — ​ ​ 213,319 ​ Customer C ​ Illinois Basin ​ ​ — ​ ​ 157,271 ​ ​ — ​ Customer D Illinois Basin/Appalachia ​ — ​ ​ 137,785 ​ — ​ ​ Trade accounts receivable from major customers totaled approximately $ 10.8 million and $ 32.0 million at December 31, 2021 and 2020, respectively. Our credit loss experience has historically been insignificant. Financial conditions of our customers could result in a material change to our credit loss expense in future periods. The coal supply agreements with Customer A expires in 2024. ​ 24. SEGMENT INFORMATION ​ We operate in the United States as a diversified natural resource company that generates operating and royalty income from the production and marketing of coal to major domestic and international utilities and industrial users as well as royalty income from oil & gas mineral interests. We aggregate multiple operating segments into four reportable segments, Illinois Basin Coal Operations, Appalachia Coal Operations, Oil & Gas Royalties and Coal Royalties. We also have an "all other" category referred to as Other, Corporate and Elimination. Our two coal operations reportable segments correspond to major coal producing regions in the eastern United States with similar economic characteristics including 138 Table of Contents coal quality, geology, coal marketing opportunities, mining and transportation methods and regulatory issues. The two coal operations reportable segments include seven mining complexes operating in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia and a coal loading terminal in Indiana on the Ohio River. Our Oil & Gas Royalties reportable segment includes our oil & gas mineral interests which are located primarily in the Permian (Delaware and Midland), Anadarko (SCOOP/STACK) and Williston (Bakken) basins. The operations within our Oil & Gas Royalties reportable segment primarily include receiving royalties and lease bonuses for our oil & gas mineral interests. Our Coal Royalties reportable segment includes coal mineral reserves and resources owned or leased by Alliance Resource Properties, which are either (a) leased to our mining complexes or (b) near our coal mining operations but not yet leased. ​ Beginning in the first quarter of 2021, we began to strategically view and manage our coal royalty activities separately from our coal operations since acquiring and managing a variety of royalty producing assets involve similar attributes. As a result, we restructured our reportable segments to better reflect this strategic view in how we manage our business and allocate resources. Prior periods have been recast to include Alliance Resource Properties within our new Coal Royalties reportable segment with offsetting recast adjustments primarily to our coal operations reportable segments and to a lesser extent, our Other, Corporate and Elimination category. Eliminations reported in Other, Corporate and Elimination were also recast to reflect intercompany royalty revenues and offsetting intercompany royalty expense resulting from our new Coal Royalties reportable segment. ​ The Illinois Basin Coal Operations reportable segment includes currently operating mining complexes (a) the Gibson County Coal, LLC's ("Gibson") mining complex, which includes the Gibson South mine, (b) the Warrior Coal, LLC ("Warrior") mining complex, (c) the River View Coal, LLC ("River View") mining complex and (d) the Hamilton mining complex. The Illinois Basin Coal Operations reportable segment also includes our Mt. Vernon Transfer Terminal, LLC ("Mt. Vernon") coal loading terminal in Indiana which currently operates on the Ohio River. ​ The Illinois Basin Coal Operations reportable segment also includes Mid-America Carbonates, LLC ("MAC") and other support services as well as non-operating mining complexes (a) Gibson North mine, which ceased production in the fourth quarter of 2019, (b) Webster County Coal, LLC's Dotiki mining complex, which ceased production in August 2019, (c) White County Coal, LLC's Pattiki mining complex, which ceased production in December 2016, (d) the Hopkins County Coal, LLC mining complex, which ceased production in April 2016, and (e) Sebree Mining, LLC's mining complex, which ceased production in November 2015. ​ The Appalachia Coal Operations reportable segment includes currently operating mining complexes (a) the Mettiki mining complex, (b) the Tunnel Ridge mining complex and (c) the MC Mining, LLC ("MC Mining") mining complex. The Mettiki mining complex includes Mettiki Coal (WV), LLC's Mountain View mine and Mettiki Coal, LLC's preparation plant. ​ The Oil & Gas Royalties reportable segment includes oil & gas mineral interests held by AR Midland and AllDale I & II and includes Alliance Minerals' equity interests in both AllDale III (Note 13 – Investments) and Cavalier Minerals. AR Midland acquired its mineral interest in the Wing Acquisition and Boulders Acquisition (Note 3 – Acquisitions). ​ Coal Royalties reportable segment includes coal mineral reserves and resources owned or leased by Alliance Resource Properties that are (a) leased to certain of our mining complexes in both the Illinois Basin Coal Operations and Appalachia Coal Operations reportable segments or (b) located near our operations and external mining operations. Approximately two thirds of the coal sold by our Coal Operations' mines is leased from our Coal Royalties entities. ​ Other, Corporate and Elimination includes marketing and administrative activities, Matrix Design Group, LLC and its subsidiaries ("Matrix Design"), Alliance Design Group, LLC ("Alliance Design") (collectively, Matrix Design and Alliance Design referred to as the "Matrix Group"), Pontiki Coal, LLC's workers' compensation and pneumoconiosis liabilities, Wildcat Insurance, which assists the ARLP Partnership with its insurance requirements, AROP Funding and Alliance Finance (both discussed in Note 8 – Long-Term Debt) and other miscellaneous activities. The eliminations included in Other, Corporate and Elimination primarily represent the intercompany coal royalty transactions described above between our Coal Royalties reportable segment and our coal operations' mines. ​ 139 Table of Contents Reportable segment results are presented below. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Coal Operations ​ Royalties ​ Other, ​ ​ ​ ​ ​ Illinois ​ ​ ​ ​ ​ Corporate and ​ ​ ​ ​ Basin Appalachia Oil & Gas Coal ​ Elimination Consolidated ​ ​ (in thousands) Year Ended December 31, 2021 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Revenues - Outside ​ $ 919,597 ​ $ 545,539 ​ $ 77,185 ​ $ 69 ​ $ 27,586 ​ $ 1,569,976 ​ Revenues - Intercompany ​ ​ — ​ ​ — ​ ​ — ​ ​ 51,402 ​ ​ ( 51,402 ) ​ ​ — ​ Total revenues (1) ​ ​ 919,597 ​ ​ 545,539 ​ ​ 77,185 ​ ​ 51,471 ​ ​ ( 23,816 ) ​ ​ 1,569,976 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Segment Adjusted EBITDA Expense (2) ​ 613,303 ​ ​ 344,332 ​ ​ 9,943 ​ ​ 18,269 ​ ​ ( 33,198 ) ​ 952,649 ​ Segment Adjusted EBITDA (3) ​ 265,292 ​ ​ 172,601 ​ ​ 68,774 ​ ​ 33,202 ​ ​ 9,383 ​ 549,252 ​ Total assets ​ 676,091 ​ ​ 420,144 ​ ​ 630,627 ​ ​ 285,943 ​ ​ 146,601 ​ 2,159,406 ​ Capital expenditures (4) ​ 60,166 ​ ​ 47,577 ​ ​ — ​ ​ 45 ​ ​ 15,196 ​ 122,984 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2020 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Revenues - Outside ​ $ 769,957 ​ $ 500,330 ​ $ 43,141 ​ $ 105 ​ $ 14,596 ​ $ 1,328,129 ​ Revenues - Intercompany ​ ​ — ​ ​ — ​ ​ — ​ ​ 42,112 ​ ​ ( 42,112 ) ​ ​ — ​ Total revenues (1) ​ ​ 769,957 ​ ​ 500,330 ​ ​ 43,141 ​ ​ 42,217 ​ ​ ( 27,516 ) ​ ​ 1,328,129 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Segment Adjusted EBITDA Expense (2) ​ 543,264 ​ ​ 320,656 ​ ​ 4,106 ​ ​ 18,249 ​ ​ ( 25,026 ) ​ 861,249 ​ Segment Adjusted EBITDA (3) ​ 213,876 ​ ​ 171,362 ​ ​ 39,773 ​ ​ 23,968 ​ ​ ( 2,490 ) ​ 446,489 ​ Total assets ​ 738,315 ​ ​ 440,815 ​ ​ 613,916 ​ ​ 288,525 ​ ​ 84,445 ​ 2,166,016 ​ Capital expenditures ​ 48,636 ​ ​ 70,960 ​ ​ — ​ ​ 12 ​ ​ 1,493 ​ 121,101 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2019 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Revenues - Outside ​ $ 1,219,601 ​ $ 644,389 ​ $ 53,036 ​ $ 23 ​ $ 44,671 ​ $ 1,961,720 ​ Revenues - Intercompany ​ ​ 16,690 ​ ​ — ​ ​ — ​ ​ 57,737 ​ ​ ( 74,427 ) ​ ​ — ​ Total revenues (1) ​ ​ 1,236,291 ​ ​ 644,389 ​ ​ 53,036 ​ ​ 57,760 ​ ​ ( 29,756 ) ​ ​ 1,961,720 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Segment Adjusted EBITDA Expense (2) ​ 791,795 ​ 424,387 ​ 7,811 ​ 21,445 ​ ​ ( 40,542 ) ​ 1,204,896 ​ Segment Adjusted EBITDA (3) ​ 349,810 ​ 215,187 ​ 46,997 ​ 36,315 ​ ​ 23,692 ​ 672,001 ​ Total assets ​ 1,092,188 ​ 489,378 ​ 643,213 ​ 292,436 ​ ​ 69,479 ​ 2,586,694 ​ Capital expenditures (4) ​ 188,928 ​ 111,729 ​ — ​ 352 ​ ​ 4,849 ​ 305,858 ​ (1) Revenues included in the Other, Corporate and Elimination column are attributable to intercompany eliminations, which are primarily the coal royalties intercompany eliminations, outside revenues at the Matrix Group and other outside miscellaneous sales and revenue activities. ​ (2) Segment Adjusted EBITDA Expense includes operating expenses, coal purchases and other income. Transportation expenses are excluded as transportation revenues are recognized in an amount equal to transportation expenses when title passes to the customer. ​ The following is a reconciliation of consolidated Segment Adjusted EBITDA Expense to Operating expenses (excluding depreciation, depletion and amortization) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2021 2020 2019 ​ ​ (in thousands) ​ Segment Adjusted EBITDA Expense ​ $ 952,649 ​ $ 861,249 ​ $ 1,204,896 ​ Outside coal purchases ​ ( 6,372 ) ​ — ​ ( 23,357 ) ​ Other income (expense) ​ ( 3,020 ) ​ ( 1,593 ) ​ 561 ​ Operating expenses (excluding depreciation, depletion and amortization) ​ $ 943,257 ​ $ 859,656 ​ $ 1,182,100 ​ ​ 140 Table of Contents (3) Segment Adjusted EBITDA is defined as net income (loss) attributable to ARLP before net interest expense, income taxes, depreciation, depletion and amortization, general and administrative expense, asset and goodwill impairments and acquisition gain. Management therefore is able to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments. Consolidated Segment Adjusted EBITDA is reconciled to net income (loss) as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2021 2020 2019 ​ ​ (in thousands) ​ Consolidated Segment Adjusted EBITDA ​ $ 549,252 ​ $ 446,489 $ 672,001 ​ General and administrative ​ ( 70,160 ) ​ ( 59,806 ) ​ ( 72,997 ) ​ Depreciation, depletion and amortization ​ ( 261,377 ) ​ ( 313,387 ) ​ ( 309,075 ) ​ Asset impairments ​ — ​ ( 24,977 ) ​ ( 15,190 ) ​ Goodwill impairment ​ ​ — ​ ​ ( 132,026 ) ​ ​ — ​ Interest expense, net ​ ( 39,141 ) ​ ( 45,478 ) ​ ( 45,496 ) ​ Acquisition gain ​ ​ — ​ ​ — ​ 177,043 ​ Income tax (expense) benefit ​ ( 417 ) ​ ( 35 ) ​ 211 ​ Acquisition gain attributable to noncontrolling interest ​ ​ — ​ ​ — ​ ​ ( 7,083 ) ​ Net income (loss) attributable to ARLP ​ $ 178,157 ​ $ ( 129,220 ) ​ $ 399,414 ​ Noncontrolling interest ​ ​ 598 ​ ​ 169 ​ ​ 7,512 ​ Net income (loss) ​ $ 178,755 ​ $ ( 129,051 ) ​ $ 406,926 ​ ​ . (4) Capital Expenditures shown exclude the AllDale Acquisition on January 3, 2019, the Wing Acquisition on August 2, 2019 and Boulders Acquisition on October 13, 2021 (Note 3 – Acquisitions) . ​ 25. SUBSEQUENT EVENTS ​ Other than the events described in Notes 8, 11 and 17, there were no subsequent events. ​ ​ 141 Table of Contents ​ SUPPLEMENTAL OIL & GAS RESERVE INFORMATION (UNAUDITED) ​ These supplemental oil & gas reserve information disclosures are required for periods in which a company has significant oil & gas producing activities. A company is considered to have significant oil & gas producing activities if any of its revenues, results of operations or assets from oil & gas producing activities exceed 10% of consolidated revenues, results of operations or assets for the year being measured. Subsequent to our 2019 acquisitions of oil and gas mineral interests, we are considered to have significant oil & gas producing activities. ​ Geographical Area of Operation ​ All of our proved oil & gas reserves are located within the continental United States with the majority concentrated in Texas, Oklahoma, New Mexico and North Dakota. The following supplemental disclosures about our proved oil & gas reserves including costs incurred, capitalized cost, results of operations and cash flows are presented on a consolidated basis. ​ Costs Incurred in Oil & Gas Property Acquisitions ​ Costs incurred in oil & gas property acquisitions are presented below: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2021 2020 2019 ​ ​ (in thousands) ​ Acquisition costs of properties ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved ​ $ 12,542 ​ $ — ​ $ 242,116 ​ Unproved ​ ​ 18,419 ​ ​ — ​ ​ 376,166 ​ Total ​ $ 30,961 ​ $ — ​ $ 618,282 ​ ​ Property acquisition costs for 2021 are related to the Boulders Acquisition. Property acquisition costs for 2019 include non-cash amounts for the AllDale Acquisition. In connection with the AllDale Acquisition, we marked our previously held equity method investments to a fair value of $307.3 million, resulting in a $177.0 million gain. See Note 3 – Acquisitions in our consolidated financial statements for more information regarding these acquisitions. ​ Oil & Gas Capitalized Costs ​ Aggregate capitalized costs related to oil & gas activities with applicable accumulated depreciation, depletion, and amortization are presented below: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of December 31, ​ ​ ​ 2021 ​ 2020 ​ ​ ​ (in thousands) ​ ​ ​ Consolidated ​ Our Share of an Equity Method Investee ​ Consolidated ​ Our Share of an Equity Method Investee ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved properties ​ $ 289,378 ​ $ 9,138 ​ $ 273,665 ​ $ 8,331 ​ Unproved properties ​ ​ 358,486 ​ ​ 19,216 ​ ​ 343,239 ​ ​ 20,287 ​ Total (1) ​ 647,864 ​ 28,354 ​ 616,904 ​ 28,618 ​ Less accumulated depreciation, depletion and amortization ​ (70,286) ​ (3,015) ​ (48,019) ​ (1,985) ​ Oil & gas properties, net ​ $ 577,578 ​ $ 25,339 ​ $ 568,885 ​ $ 26,633 ​ ​ (1) The change in total capitalized cost in 2021 reflects the acquisition of proved and unproved properties in the Boulders Acquisition. See Note 3 – Acquisitions of our consolidated financial statements for more information about the Boulders Acquisition. ​ 142 Table of Contents Results of Operations from Oil & Gas Activities ​ The following schedule sets forth the revenues and expenses related to our oil & gas mineral interests. It does not include any interest costs or general and administrative costs, and therefore, is not necessarily indicative of the contribution to the results of our Oil & Gas Royalties segment. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2021 2020 2019 ​ ​ (in thousands) ​ Consolidated activities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil & gas royalties ​ $ 74,988 ​ $ 42,912 ​ $ 51,735 ​ Other revenues ​ ​ 2,197 ​ ​ 229 ​ ​ 1,301 ​ Production costs and severance taxes ​ ​ (7,396) ​ ​ (4,611) ​ ​ (7,859) ​ Depreciation, depletion and amortization ​ ​ (22,267) ​ ​ (25,376) ​ ​ (22,658) ​ Total results of oil & gas activities ​ $ 47,522 ​ $ 13,154 ​ $ 22,519 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Our share of an equity method investee ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil & gas royalties ​ $ 3,788 ​ $ 2,674 ​ $ 3,200 ​ Other revenues ​ ​ 66 ​ ​ 22 ​ ​ 190 ​ Production costs and severance taxes ​ ​ (472) ​ ​ (374) ​ ​ (411) ​ Depreciation, depletion and amortization ​ ​ (787) ​ ​ (748) ​ ​ (854) ​ Total results of oil & gas activities ​ $ 2,595 ​ $ 1,574 ​ $ 2,125 ​ Oil & Gas Reserves ​ Proved oil & gas reserve estimates as of December 31, 2021 were prepared by our internal engineering team and 95% of those reserves were audited by Netherland, Sewell & Associates, Inc., independent petroleum engineers. Proved reserves are estimated under existing economic and operating conditions based upon the 12-month unweighted average of the first-of-the-month prices. ​ Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors. ​ 143 Table of Contents The net proved developed and undeveloped oil & gas reserves quantities of the mineral interests attributable to us are summarized below: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude Oil Natural Gas Natural Gas Liquids Total ​ (MBbl) (MMcf) (MBbl) (MBOE) Consolidated activities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of January 1, 2019 ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ Purchases of minerals in place ​ ​ 6,509 ​ ​ 30,055 ​ ​ 3,477 ​ ​ 14,995 ​ Revisions of previous estimates ​ ​ 1,015 ​ ​ 1,956 ​ ​ (548) ​ ​ 793 ​ Production ​ ​ (700) ​ ​ (3,382) ​ ​ (347) ​ ​ (1,611) ​ As of December 31, 2019 (1) ​ ​ 6,824 ​ ​ 28,629 ​ ​ 2,582 ​ ​ 14,177 ​ Revisions of previous estimates ​ ​ (194) ​ ​ 2,679 ​ ​ 343 ​ ​ 596 ​ Extensions and discoveries ​ ​ 1,095 ​ ​ 3,039 ​ ​ 347 ​ ​ 1,949 ​ Production ​ ​ (905) ​ ​ (3,301) ​ ​ (337) ​ ​ (1,792) ​ Sales of minerals in place ​ ​ (18) ​ ​ (29) ​ ​ (3) ​ ​ (26) ​ As of December 31, 2020 (1) ​ ​ 6,802 ​ ​ 31,017 ​ ​ 2,932 ​ ​ 14,904 ​ Purchases of minerals in place ​ ​ 287 ​ ​ 2,149 ​ ​ 332 ​ ​ 977 ​ Revisions of previous estimates ​ ​ (403) ​ ​ (90) ​ ​ 197 ​ ​ (221) ​ Extensions and discoveries ​ ​ 629 ​ ​ 159 ​ ​ 335 ​ ​ 991 ​ Production ​ ​ (794) ​ ​ (3,069) ​ ​ (357) ​ ​ (1,663) ​ As of December 31, 2021 (1) ​ ​ 6,521 ​ ​ 30,166 ​ ​ 3,439 ​ ​ 14,988 ​ (1) Proved reserves of approximately 1,285 MBOE, 972 MBOE and 1,208 MBOE were attributable to noncontrolling interests, as of December 31, 2021, 2020 and 2019, respectively. ​ 144 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude Oil Natural Gas Natural Gas Liquids Total ​ (MBbl) (MMcf) (MBbl) (MBOE) Our share of an equity method investee ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of January 1, 2019 ​ ​ 295 ​ ​ 2,205 ​ ​ — ​ ​ 662 ​ Revisions of previous estimates ​ ​ 78 ​ ​ 11 ​ ​ 153 ​ ​ 234 ​ Sales of minerals in place ​ ​ (7) ​ ​ (8) ​ ​ — ​ ​ (8) ​ Production ​ ​ (41) ​ ​ (282) ​ ​ (17) ​ ​ (105) ​ As of December 31, 2019 ​ ​ 325 ​ ​ 1,926 ​ ​ 136 ​ ​ 783 ​ Revisions of previous estimates ​ ​ — ​ ​ (1) ​ ​ (2) ​ ​ (3) ​ Extensions and discoveries ​ ​ 62 ​ ​ 461 ​ ​ 54 ​ ​ 193 ​ Production ​ ​ (44) ​ ​ (334) ​ ​ — ​ ​ (100) ​ As of December 31, 2020 ​ ​ 342 ​ ​ 2,052 ​ ​ 188 ​ ​ 873 ​ Sales of minerals in place ​ ​ (9) ​ ​ (15) ​ ​ — ​ ​ (12) ​ Revisions of previous estimates ​ ​ (50) ​ ​ 320 ​ ​ (53) ​ ​ (51) ​ Extensions and discoveries ​ ​ 73 ​ ​ 450 ​ ​ 43 ​ ​ 190 ​ Production ​ ​ (31) ​ ​ (421) ​ ​ — ​ ​ (101) ​ As of December 31, 2021 ​ ​ 325 ​ ​ 2,386 ​ ​ 178 ​ ​ 899 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total consolidated and equity interests in reserves at December 31, 2021 ​ ​ 6,846 ​ ​ 32,552 ​ ​ 3,617 ​ ​ 15,887 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net proved developed reserves as of December 31, 2019 ​ ​ 5,766 ​ ​ 24,449 ​ ​ 2,009 ​ ​ 11,850 ​ Net proved developed reserves as of December 31, 2020 ​ ​ 5,073 ​ ​ 23,504 ​ ​ 2,252 ​ ​ 11,244 ​ Net proved developed reserves as of December 31, 2021 ​ ​ 5,493 ​ ​ 28,426 ​ ​ 3,039 ​ ​ 13,269 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net proved undeveloped reserves as of December 31, 2019 ​ ​ 1,383 ​ ​ 6,106 ​ ​ 709 ​ ​ 3,110 ​ Net proved undeveloped reserves as of December 31, 2020 ​ ​ 2,071 ​ ​ 9,565 ​ ​ 868 ​ ​ 4,533 ​ Net proved undeveloped reserves as of December 31, 2021 ​ ​ 1,353 ​ ​ 4,126 ​ ​ 578 ​ ​ 2,618 ​ ​ Natural gas reserves are converted to BOE based on a 6:1 ratio: six Mcf of natural gas converts to one BOE. ​ Notable changes in proved reserves during the year ended December 31, 2019, included: ​ ● Purchases of minerals in place: The increases represent the acquisition of mineral interests in the AllDale and Wing Acquisitions. Please see Note 3 – Acquisitions in our consolidated financial statements for more information. ​ ● Revisions: Increases in oil & gas are also due to changes in the underlying commodity prices during the year and revisions of previous quantity estimates. ​ Notable changes in proved reserves during the year ended December 31, 2020, included: ​ ● Net change due to extensions and discoveries: The increases are a result of the addition of new properties by the operators under which we own mineral interests. In 2020, a net addition of 2,142 MBOE occurred primarily from the completion of 655 new wells on our acreage and from the addition of 877 new proved undeveloped locations due to permitting and drilling activity. ​ ● Revisions: Increases in oil & gas are also due to changes in the underlying commodity prices during the year and revisions of previous quantity estimates. ​ 145 Table of Contents Notable changes in proved reserves during the year ended December 31, 2021, included: ​ ● Net change due to extensions and discoveries: The increases are a result of the addition of new properties by the operators under which we own mineral interests. In 2021, a net addition of 1,181 MBOE occurred primarily from the completion of 843 new wells on our acreage and from the addition of 474 new proved undeveloped locations due to permitting and drilling activity. ​ ● Revisions: Increases in oil & gas are also due to changes in the underlying commodity prices during the year and revisions of previous quantity estimates. ​ Standardized Measure of Discounted Future Net Cash Flows ​ In accordance with SEC and FASB requirements, future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted average of first-of-the-month commodity prices for the year ended December 31, 2021. All prices are adjusted for quality, transportation fees, energy content and regional basis differentials. Future cash inflows are computed by applying applicable prices relating to our proved reserves to the year end quantities of those reserves. Future production costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses deducted from future production revenues in the calculation of the standardized measure because the ARLP Partnership is generally not subject to federal income taxes. The ARLP Partnership is subject to certain state based taxes; however, these amounts are not material. See Note 2 – Summary of Significant Accounting Policies for further discussion. ​ While due care was taken in preparation of the following cash flow projections, we do not represent that this data is the fair value of our oil & gas properties, or a fair estimate of the present value of cash flows to be obtained from their development and production. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices are expected to vary significantly from those used and actual costs may vary. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of December 31, ​ ​ ​ 2021 ​ 2020 ​ 2019 ​ ​ ​ (in thousands) ​ ​ ​ Consolidated ​ Our Share of an Equity Method Investee ​ Consolidated ​ Our Share of an Equity Method Investee ​ Consolidated ​ Our Share of an Equity Method Investee ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Future cash inflows ​ $ 577,114 ​ $ 31,636 ​ $ 302,112 ​ $ 15,414 ​ $ 463,972 ​ $ 24,372 ​ Future production costs and severance taxes ​ ​ (43,474) ​ ​ (2,484) ​ ​ (21,555) ​ ​ (1,244) ​ ​ (34,997) ​ ​ (1,515) ​ Future net cash flows (undiscounted) ​ 533,640 ​ 29,152 ​ 280,557 ​ 14,170 ​ 428,975 ​ 22,857 ​ Annual discount 10% for estimated timing ​ (260,718) ​ (13,980) ​ (130,341) ​ (6,406) ​ (198,025) ​ (10,642) ​ Total standardized measure (1) ​ $ 272,922 ​ $ 15,172 ​ $ 150,216 ​ $ 7,764 ​ $ 230,950 ​ $ 12,215 ​ (1) Includes standardized discounted future net cash flows of approximately $17.9 million, $5.2 million and $12.5 million attributable to noncontrolling interests in the ARLP Partnership's consolidated subsidiaries as of December 31, 2021, 2020 and 2019, respectively. ​ 146 Table of Contents The average realized product prices weighted by production over the remaining lives of the properties are presented in the table below: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the Year Ended December 31, ​ ​ 2021 ​ 2020 ​ 2019 ​ Oil (per Bbl) ​ $ 63.57 ​ $ 36.95 ​ $ 52.32 ​ Natural gas (per Mcf) ​ ​ 2.98 ​ ​ 0.88 ​ ​ 1.83 ​ NGLs (per Bbl) ​ ​ 21.13 ​ ​ 7.99 ​ 21.95 ​ ​ Changes in the standardized measure of discounted future net cash flows related to the proved oil & gas reserves of the properties are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of December 31, ​ ​ ​ 2021 ​ 2020 ​ 2019 ​ ​ ​ (in thousands) ​ ​ ​ Consolidated ​ Our Share of an Equity Method Investee ​ Consolidated ​ Our Share of an Equity Method Investee ​ Consolidated ​ Our Share of an Equity Method Investee ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Standardized measure, beginning of year ​ $ 150,216 ​ $ 7,764 ​ $ 230,950 ​ $ 12,215 ​ $ — ​ $ 12,845 ​ Purchases and sales of reserves in place, less related costs ​ ​ 15,358 ​ ​ (264) ​ ​ (567) ​ ​ — ​ ​ 231,287 ​ ​ (252) ​ Sales, net of production costs ​ ​ (67,592) ​ ​ (3,316) ​ ​ (38,301) ​ ​ (2,300) ​ ​ (43,875) ​ ​ (2,788) ​ Net changes due to extensions and discoveries ​ ​ 34,284 ​ ​ 3,613 ​ ​ 15,770 ​ ​ 1,344 ​ ​ — ​ ​ — ​ Net changes in prices and production costs ​ ​ 120,103 ​ ​ 6,753 ​ ​ (67,524) ​ ​ (3,906) ​ ​ 10,533 ​ ​ (2,517) ​ Revisions of previous quantity estimates ​ ​ 8,310 ​ ​ (871) ​ ​ (2,843) ​ ​ (378) ​ ​ 14,560 ​ ​ 3,398 ​ Accretion of discount ​ ​ 11,745 ​ ​ 545 ​ ​ 16,216 ​ ​ 870 ​ ​ 18,403 ​ ​ 1,284 ​ Changes in timing and other ​ ​ 498 ​ ​ 948 ​ ​ (3,485) ​ ​ (81) ​ ​ 42 ​ ​ 245 ​ Net increase (decrease) in standardized measures ​ ​ 122,706 ​ ​ 7,408 ​ ​ (80,734) ​ ​ (4,451) ​ 230,950 ​ (630) ​ Standardized measure, end of year ​ $ 272,922 ​ $ 15,172 ​ $ 150,216 ​ $ 7,764 ​ $ 230,950 ​ $ 12,215 ​ ​ Net change in prices and production costs occur from one reporting period to another when the SEC reporting price for that period changes. For 2021, this was a major component of the overall reserves value change from 2020 due to the surge in global energy demand during the recovery from the economic downturn related to the COVID-19 pandemic during 2020. For 2020, net changes in prices and production costs were major components of the overall reserves value change from 2019 due mainly to the COVID-19 pandemic and the subsequent decline in oil and gas demand. ​ The standardized measure amount at the beginning of 2019 for our share of an Equity Method Investee reflects only our proportionate share of AllDale III's beginning of the year standardized measure amount. Our previously held equity method investments in AllDale I & II, as a result of the AllDale Acquisition in 2019, are now consolidated on our financial statements. Accordingly, we reflect the activity for AllDale I & II in our consolidated standardized measure amounts and not the Equity Method amounts. ​ 147 Table of Contents ​ SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT ALLIANCE RESOURCE PARTNERS, L.P. ​ CONDENSED BALANCE SHEETS (PARENT) DECEMBER 31, 2021 AND 2020 (In thousands, except unit data) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2021 2020 ​ ASSETS ​ ​ ​ ​ ​ CURRENT ASSETS: ​ ​ ​ ​ ​ ​ ​ Cash and cash equivalents ​ $ 2,173 ​ $ 2,174 ​ Total current assets ​ 2,173 ​ 2,174 ​ OTHER ASSETS: ​ ​ ​ ​ ​ ​ ​ Investments in consolidated subsidiaries ​ 1,277,110 ​ 1,146,491 ​ Total other assets ​ 1,277,110 ​ 1,146,491 ​ TOTAL ASSETS ​ $ 1,279,283 ​ $ 1,148,665 ​ ​ ​ ​ ​ ​ ​ ​ ​ LIABILITIES AND PARTNERS' CAPITAL ​ ​ ​ ​ ​ ​ ​ CURRENT LIABILITIES: ​ ​ ​ ​ ​ ​ ​ Accrued taxes other than income taxes ​ $ 100 ​ $ 100 ​ Total current liabilities ​ 100 ​ 100 ​ Total liabilities ​ 100 ​ 100 ​ ​ ​ ​ ​ ​ ​ ​ ​ PARTNERS' CAPITAL: ​ ​ ​ ​ ​ ​ ​ Limited Partners - Common Unitholders 127,195,219 units outstanding ​ 1,279,183 ​ 1,148,565 ​ TOTAL LIABILITIES AND PARTNERS' CAPITAL ​ $ 1,279,283 ​ $ 1,148,665 ​ See accompanying notes. ​ CONDENSED STATEMENTS OF OPERATIONS (PARENT) FOR THE YEARS ENDED DECEMBER 31, 2021, 2020 AND 2019 (In thousands, except unit and per unit data) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2021 2020 2019 EXPENSES: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative ​ $ — ​ $ — ​ $ 41 ​ Total operating expenses ​ — ​ — ​ 41 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ INCOME (LOSS) FROM OPERATIONS ​ — ​ — ​ ( 41 ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest income ​ — ​ 24 ​ 34 ​ Equity in earnings of consolidated subsidiaries ​ 178,157 ​ ( 129,244 ) ​ 399,421 ​ NET INCOME (LOSS) ATTRIBUTABLE TO ARLP ​ $ 178,157 ​ $ ( 129,220 ) ​ $ 399,414 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ EARNINGS PER LIMITED PARTNER UNIT - BASIC AND DILUTED ​ $ 1.36 ​ $ ( 1.02 ) ​ $ 3.07 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ WEIGHTED-AVERAGE NUMBER OF UNITS OUTSTANDING – BASIC AND DILUTED ​ 127,195,219 ​ 127,164,659 ​ 128,116,670 ​ See accompanying notes. ​ 148 Table of Contents CONDENSED STATEMENTS OF CASH FLOWS (PARENT) FOR THE YEARS ENDED DECEMBER 31, 2021, 2020 AND 2019 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 2020 2019 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ CASH FLOWS FROM OPERATING ACTIVITIES: ​ $ 52,157 ​ $ 51,751 ​ $ 278,308 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ CASH FLOWS FROM FINANCING ACTIVITIES: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Distributions paid to Partners ​ ​ ( 52,158 ) ​ ( 51,753 ) ​ ( 278,425 ) ​ Net cash used in financing activities ​ ( 52,158 ) ​ ( 51,753 ) ​ ( 278,425 ) ​ NET CHANGE IN CASH AND CASH EQUIVALENTS ​ ( 1 ) ​ ( 2 ) ​ ( 117 ) ​ CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ​ 2,174 ​ 2,176 ​ 2,293 ​ CASH AND CASH EQUIVALENTS AT END OF PERIOD ​ $ 2,173 ​ $ 2,174 ​ $ 2,176 ​ See accompanying notes. ​ ​ NOTES TO FINANCIAL INFORMATION (PARENT) ​ 1. BASIS OF PRESENTATION ​ In these parent-company-only financial statements, our investment in consolidated subsidiaries is stated at cost plus equity in undistributed earnings of subsidiaries and reduced by distributions received from subsidiaries since the date of acquisition. These parent-company-only financial statements should be read in conjunction with our consolidated financial statements in "Item 8. Financial Statements and Supplementary Data" of this Annual Report on Form 10-K. ​ 2. GUARANTEES ​ As the parent of the Intermediate Partnership, we are a guarantor of both the Credit Agreement and Senior Notes discussed in "Item 8. Financial Statements and Supplementary Data—Note 8 – Long-Term Debt" of this Annual Report on Form 10-K. In addition to these guarantees, we have provided guarantees on surety indemnity agreements and financially guaranteed certain coal supply agreements. The duration of these guarantees varies. The maximum undiscounted potential future payment obligation for our guarantees of certain coal supply agreements as of December 31, 2021 is approximately $ 146.7 million as a result of elevated market prices. These guarantees provide for compensation to customers based on additional cost to the customer to replace any contracted tons that our subsidiaries fail to deliver. We do not expect to make any payments under these guarantees. ​ 3. CASH DISTRIBUTIONS RECEIVED ​ We received distributions of $ 52.2 million, $ 51.8 million and $ 278.4 million from our consolidated subsidiaries during the years ended December 31, 2021, 2020, and 2019, respectively. ​ ​ ​ ​ ​ 149 Table of Contents ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANT ON ACCOUNTING AND FINANCIAL DISCLOSURE ​ None. ​