Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2025

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.

Business Combinations

A business consists of inputs and processes applied to those inputs that have the ability to contribute to the creation of outputs. We account for the acquisition of a business as a business combination, where 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. However, if substantially all the fair value of the assets acquired is concentrated in a single

identifiable asset or a group of similar identifiable assets with the same risk profile, the acquisition is accounted for as an asset acquisition and recorded at cost.

Use of Estimates

Estimates

The preparation of consolidated financial statements in conformity with generally accepted accounting principles of the United States 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:

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Asset retirement obligations;

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Pension obligations;

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Workers’ compensation and pneumoconiosis obligations;

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Acquisition related purchase price allocations;

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Life of mine assumptions;

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Oil & gas reserve quantities and carrying amounts;

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Determination of oil & gas revenue accruals; and

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Contingent consideration liability.

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 on 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 techniques used in our fair value measurements are based on 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:

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Level 1 – Quoted prices for identical assets and liabilities in active markets that we have the ability to access at the measurement date.

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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.

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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. At times the ARLP Partnership maintains deposits in federally insured financial institutions in excess of stated federally insured limits.

Cash Management

The cash flows from operating activities section of our consolidated statements of cash flows reflects adjustments of $3.3 million and $6.7 million representing book overdrafts at December 31, 2024 and 2023, respectively. We did not have material book overdrafts at December 31, 2025.

Inventories

Coal inventories are stated at the lower of cost or net realizable value on a first-in, first-out basis. Supply, finished goods, work in process and raw materials inventories are stated at an average cost basis, less a reserve for obsolete and surplus items.

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,
		2025			2024

		(in thousands)

Advance royalties, affiliates (see Note 21– Related-Party Transactions)		$	69,126		$	67,189
Advance royalties, third-parties			13,782			14,497
Total advance royalties		$	82,908		$	81,686

Digital Assets

We began our crypto-mining activities during the second half of 2020 as we started mining bitcoin as a pilot project to monetize already paid for, yet underutilized, electricity load. We continue to periodically be awarded digital assets through our crypto-mining activities. The awards are accounted for as revenue and valued at the exchange quoted price at the time they are awarded. Beginning January 1, 2024, with our adoption of the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2023-08, Intangibles - Goodwill and Other - Crypto Assets (Subtopic 350-60) (“ASU 2023-08”), the digital assets we hold are subsequently remeasured to fair value based on the exchange quoted price as of the balance sheet date and included on our consolidated balance sheets within the Digital assets line item. The activity from remeasurement of digital assets to fair value is reflected in our consolidated statements of income within the Change in fair value of digital assets line item. Digital assets sold for cash nearly immediately after they are awarded to us for mining activities are presented as cash flows from operating activities, while other sales are reflected as cash flows from investing activities in our consolidated statements of cash flows. Our realized gains or losses are determined as the difference between the proceeds received when the digital assets are sold and our cost basis in the digital assets. Our cost basis is the value of the digital assets when they are awarded less any impairment recognized prior to our adoption of ASU 2023-08. We use a first-in, first-out methodology to assign costs to our digital assets in the calculation of our realized gains or losses. See Note 7 – Digital Assets for additional information.

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. Processing facilities and mineral rights, assuming current production estimates, are depreciated or depleted using the units-of-production method. Mining equipment and other plant and equipment assets are depreciated principally using the straight-line method over the remaining estimated life of each mine.

Buildings, office equipment and improvements are amortized straight line over their estimated useful lives. 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.

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 of an asset group may not be recoverable based on estimated undiscounted future cash flows. To the extent the carrying amount of an asset group is not recoverable based on undiscounted cash flows, the amount of impairment is measured by the difference between the carrying value and the fair value (See Note 9 – 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 resources are the quantities expected to be recovered through the 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.

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. The measurement alternative 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. 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 account for our ownership interests in Infinitum and Ascend Elements, Inc. (“Ascend”) as equity securities without readily determinable fair values. See Note 10 – Investments for further discussion of these investments.

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 entity at the investment date, if any, is amortized over the lives of the related assets that gave rise to the difference.

In the event our investments contain complex distribution structures, we use the hypothetical liquidation at book value (“HLBV”) method or other reasonable allocation method to determine the appropriate allocation of income or loss that reflects the economics over the life of the investment and upon liquidation. Under the HLBV method, income or loss of the investee is allocated based on hypothetical amounts that each investor would be entitled to receive if the net assets held were liquidated at book value at the end of each period, adjusted for any contributions made and distributions received during the period.

We hold equity method investments in AllDale Minerals III, LP (“AllDale III”), Francis Renewable Energy, LLC (“Francis”), NGP Energy Transition IV, L.P. (“NGP ET IV”) and Gavin Generation. See Note 3 – Variable Interest Entities for further discussion of our equity method investments.

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.

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 36 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 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.

Capitalized Implementation Costs of Cloud-Based Software

Costs incurred in the implementation of cloud-based software arrangements, including the costs of the software, materials, consultants, and payroll and payroll related costs for employees incurred are capitalized. Planning costs incurred prior to the implementation of these arrangements and costs not qualifying for capitalization are charged to expense when incurred. Capitalized implementation costs are amortized on a straight-line basis over their useful life. We have capitalized $10.9 million in implementation costs related to various cloud-based software arrangements. Because none of the cloud-based software arrangements had begun as of December 31, 2025, no amortization expense has been recognized for the years ended December 31, 2025, 2024 and 2023. Our capitalized implementation costs of cloud-based software arrangements are included in Other long-term assets on our consolidated balance sheets.

Common Unit-Based Compensation

We maintain the Long-Term Incentive Plan (“LTIP”) for certain key employees and executive officers. Pursuant to 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 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 by the compensation committee of our general partner (“Compensation Committee”). The vesting of all restricted units is subject to the satisfaction of certain financial tests. Assuming the financial tests are met, restricted units issued to LTIP participants generally cliff vest on January 1st of the third year following the issuance of such restricted units. We expect to settle restricted unit grants by issuing ARLP common units, except for the portion of the restricted units that will satisfy our tax withholding obligations. As provided under the distribution equivalent rights (“DERs”) provisions of the LTIP and the terms of the restricted unit awards, all currently outstanding 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 a value equal to the cash distributions we make to unitholders during the vesting period.

The fair value of restricted common unit grants under the LTIP are determined on the grant date of the award and recognized as compensation expense over the requisite service period. The corresponding liability is classified as equity and included in limited partners’ capital in the consolidated financial statements. If it is not probable that the restricted units will vest for a particular grant, any previously expensed amounts for that grant are reversed, and no future expense will be recognized for that grant other than amounts provided for under minimum-value guarantees. We account for forfeitures of non-vested restricted unit grants as they occur. If vesting is no longer considered probable for a particular grant, 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 utilized the Supplemental Executive Retirement Plan (“SERP”) to provide deferred compensation benefits for certain executive officers. All allocations made to participants under the SERP were made in the form of “phantom” ARLP units. The SERP was administered by the Compensation Committee.

Our directors participated 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 was established and credited with notional common units of ARLP, described in the Directors’ Deferred Compensation Plan as “phantom” units.

For both the SERP and Directors’ Deferred Compensation Plan, when quarterly cash distributions were made with respect to ARLP common units, an amount equal to such quarterly distribution was credited to each participant’s notional account as additional phantom units and recorded as compensation expense. All grants of phantom units under the SERP and Directors’ Deferred Compensation Plan vested immediately.

On December 16, 2024, the SERP and Directors’ Deferred Compensation Plan were terminated, and final distributions of applicable plan accounts were settled in cash. We have no further obligations under the SERP or the Directors’ Deferred Compensation Plan.

Workers' Compensation and Pneumoconiosis (Black Lung) Benefits

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.

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.

Pension Benefits

The funded status of our pension benefit plan is recognized separately in our consolidated balance sheets as an asset. The funded status is the difference between the fair value of plan assets and the plan’s benefit obligation. In December 2025, we entered into a pension buy-in transaction with an insurance carrier by purchasing a buy-in contract to secure pension benefits for plan participants. The buy-in contract is accounted for as a plan asset as we retain the underlying pension obligation. Subsequent to the buy-in, we measure the pension obligation at an amount equal to the fair value of the buy-in contract, reflecting the rate at which the obligation could be effectively settled. Accordingly, the discount rate used to measure the obligation reflects the rate at which the obligation could be effectively settled, as evidenced by the pricing of the buy-in contract. Prior to the buy-in, pension obligations and net periodic benefit costs were actuarially determined and impacted by various assumptions and estimates including expected return on assets, discount rates, mortality assumptions, employee turnover rates and retirement dates.

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. As of December 31, 2025 (first effective for 2026), this includes the expected return of the buy-in contract which is consistent with the discount rate used to measure the related benefit obligation, as the contract is designed to generate cash flows that reimburse the plan for benefit payments.

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.

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 an asset retirement obligation in the period incurred or acquired and a corresponding amount is capitalized as part of the related long-lived asset and depreciated on a units-of-production basis. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in anticipated timing of reclamation activities),

adjustments to the obligation and asset are recognized at the present value of the change in obligation. For locations that have been fully depleted or closed, the present value of the change in obligation is recorded to operating expenses. Accretion of the asset retirement obligation is recognized over time and until reclamation obligations are satisfied.

Asset retirement obligations primarily relate to mine site reclamation activities, which includes permanently sealing portals at underground mines, reclaiming the final pits for both our underground mines and past surface mines, removing or covering refuse piles and settling ponds, water treatment, and dismantling preparation plants, other facilities and roadway infrastructure. Federal and state laws require bonds to secure our obligations to reclaim lands used for mining and are typically renewed on an annual basis.

Revenue Recognition

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 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 on 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 mineral interests are estimated and included in 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 unless new production information is received prior to the payment allowing us to update the estimate recorded.

Income Taxes

We are not a taxable entity for federal or state income tax purposes; the tax effect of our activities accrues to our unitholders. Although publicly traded partnerships as a general rule are 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.

Our subsidiary Alliance Minerals within our Oil & Gas Royalties segment and certain other subsidiaries within our Other, Corporate and Elimination category are subject to federal and state income taxes. We use the liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (ii) operating losses and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax status or a change in tax rates on deferred tax assets and liabilities is recognized in the period the change in status is elected or rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

New Accounting Standards Issued and Adopted, and Issued and Not Yet Adopted

New Accounting Standards Issued and Adopted

In December 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 primarily requires enhanced disclosures to (1) disclose specific categories in the rate reconciliation, (2) disclose the amount of income taxes paid and expensed disaggregated by federal, state, and foreign taxes, with further disaggregation by individual jurisdictions if certain criteria are met, and (3) disclose income (loss) from continuing operations before income tax (benefit) disaggregated between domestic and foreign. The adoption of ASU 2023-09 did not have a material effect on our consolidated financial statements. The new disclosure requirements were applied prospectively beginning with the year ended December 31, 2025. See Note 22 – Income Taxes.

New Accounting Standards Issued and Not Yet Adopted

In November 2024, the FASB issued ASU 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40) (“ASU 2024-03”). ASU 2024-03 requires the disclosure of additional information about specific expense categories in the notes to the financial statements to provide enhanced transparency into the nature and function of expenses. ASU 2024-03 is effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027, with early adoption permitted. We are currently evaluating the impact ASU 2024-03 will have on our consolidated financial statements and related disclosures.

In September 2025, the FASB issued ASU 2025-06, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Targeted Improvements to the Accounting for Internal-Use Software (“ASU 2025-06”). ASU 2025-06 improves the accounting for software development costs by removing references to software development stages so that the accounting is neutral to different software development methods. ASU 2025-06 is effective for fiscal years beginning

after December 15, 2027 and interim periods within those fiscal years, with early adoption permitted. ASU 2025-06 can be applied on a prospective basis, a modified basis for in-process projects or a retrospective basis. We are evaluating the impact of ASU 2025-06 on our results of operations, cash flows, financial condition and related disclosures.

ALLIANCE RESOURCE PARTNERS LP 10-K