NACCO INDUSTRIES INC

NOTE 1—Principles of Consolidation and Nature of Operations

The accompanying Consolidated Financial Statements include the accounts of NACCO Industries, Inc.® (NACCO) and its wholly owned subsidiary, NACCO Natural Resources Corporation® (NACCO Natural Resources, and with NACCO collectively, the Company, we, our or us). NACCO Natural Resources brings natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through our robust portfolio of businesses. We operate under three business segments: Utility Coal Mining, Contract Mining and Minerals and Royalties. The Utility Coal Mining segment, operated by North American Coal®, manages surface coal mines that are exclusive, long-term fuel providers for power generation companies. The Contract Mining segment, operated by North American Mining®, is a leading provider of a broad range of specialized, long-term contract mining services. The Minerals and Royalties segment, which includes the Catapult Mineral Partners®(Catapult) business, acquires and promotes the development of mineral and royalty interests and other related investments.

In addition to the reportable segments discussed above, we also operate other businesses that are not currently reported as separate segments. These businesses complement our existing operations and support our long-term growth strategic objectives. Mitigation Resources of North America® (Mitigation Resources) provides natural resource restoration and reclamation services that include stream and wetland mitigation solutions. ReGen Resources is pursuing opportunities to develop new power generation resources.

We also have items not directly attributable to an operating segment. These items primarily include administrative costs related to public company reporting requirements, including management and board compensation, the financial results of developing businesses and Bellaire Corporation (Bellaire). Bellaire manages long-term liabilities related to former Eastern U.S. underground mining activities.

During 2025, we changed the names of our reportable segments to make it easier for our stakeholders to understand the business activities within each segment. The Utility Coal Mining, Contract Mining and Minerals and Royalties segments were formerly the Coal Mining, North American Mining and Minerals Management segments, respectively. There were no changes to the composition of each segment and therefore no changes to historical segment reporting.

See Note 15 to the Consolidated Financial Statements for further discussion of segment reporting. Our operating segments are further described below:

Utility Coal Mining Segment

The Utility Coal Mining segment operates surface coal mines under exclusive, long-term contracts to supply 100% of the fuel requirements for adjacent power plants and a synfuels plant. Each mine is fully integrated with the operation of these facilities.

As of December 31, 2025, the Utility Coal Mining segment's operating coal mines were: The Coteau Properties Company (Coteau), Coyote Creek Mining Company, LLC (Coyote Creek), The Falkirk Mining Company (Falkirk) and Mississippi Lignite Mining Company (MLMC). Coteau, Falkirk and Coyote Creek are in North Dakota and MLMC is in Mississippi. Each of these mines produce lignite coal. While MLMC’s coal supply contract contains a take or pay provision, all other coal supply contracts are requirements contracts. Certain coal supply contracts can be terminated early, which would result in a reduction to future earnings.

The MLMC contract is the only coal supply contract in which we are responsible for all operating costs, capital requirements and final mine reclamation; therefore, MLMC is consolidated within our financial statements. MLMC sells coal to its customer at a contractually agreed-upon price which adjusts monthly, primarily based on changes in the level of established indices which reflect general U.S. inflation rates and includes adjustments for coal quality and certain reimbursable costs. Profitability at MLMC is affected by customer demand for coal, changes in the contractually determined sales price and actual costs incurred. MLMC's customer operates the Red Hills Power Plant, which supplies electricity to the Tennessee Valley Authority (TVA) under a long-term power purchase agreement. MLMC’s contract with its customer runs through April 1, 2032. Current mine area reserves are sufficient to meet contractual requirements through the 2032 contract term. TVA’s power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables. The decision regarding which power plants to dispatch is determined by TVA. As a significant portion of MLMC’s costs are fixed, reduction in dispatch and/or reduced mechanical availability of the Red Hills Power Plant can materially reduce operating results at MLMC. Conversely, periods of higher dispatch can improve results. The Red Hills Power Plant operated at below full baseload capacity and experienced periods of reduced mechanical availability during 2024 and 2025. These factors increased per ton operating costs which adversely affected operating results in both 2024 and 2025.

In December 2023, MLMC received notice from its customer related to a boiler issue at the Red Hills Power Plant. While this issue has been resolved, it resulted in a reduction in customer demand which had a significant impact on our results of operations during 2024. We recognized income of $13.6 million in 2024 related to business interruption insurance recoveries that partially offset losses related to the boiler outage.

The Sabine Mining Company (Sabine) operates the Sabine Mine in Texas. All production from Sabine was delivered to Southwestern Electric Power Company's (SWEPCO) Henry W. Pirkey Plant (the Pirkey Plant). SWEPCO is an American Electric Power (AEP) company. As a result of the early retirement of the Pirkey Plant, Sabine ceased deliveries and commenced final reclamation on April 1, 2023. Funding for mine reclamation is the responsibility of SWEPCO, and Sabine receives compensation for providing mine reclamation services. Sabine will provide mine reclamation services through September 30, 2026. As of October 1, 2026, SWEPCO is obligated to acquire all of the capital stock of Sabine and complete the remaining mine reclamation.

At Coteau, Coyote Creek and Falkirk, we are paid a management fee per ton of coal or heating unit (MMBtu) delivered. Each contract specifies the indices and mechanics by which fees change over time, generally in line with broad measures of U.S. inflation. Our customers are responsible for funding all mine operating costs, including final mine reclamation, and directly or indirectly providing all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations while providing predictable income and cash flow with minimal capital investment. Other than at Coyote Creek, debt financing provided by or supported by the customers is without recourse to us. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further discussion of Coyote Creek's guarantees.

Coteau, Coyote Creek, Falkirk and Sabine each meet the definition of a variable interest entity (VIE). In each case, NACCO is not the primary beneficiary of the VIE as we do not exercise financial control; therefore, we do not consolidate the results of these operations within our financial statements. Instead, these contracts are accounted for as equity method investments. We regularly evaluate if there are reconsideration events which could change our conclusion as to whether these entities meet the definition of a VIE and the determination of the primary beneficiary. The income before income taxes associated with these VIEs is reported as Earnings of unconsolidated operations on the Consolidated Statements of Operations and our investment is reported on the line Investments in unconsolidated subsidiaries in the Consolidated Balance Sheets. The mines that meet the definition of a VIE are referred to collectively as the Unconsolidated Subsidiaries. For tax purposes, the Unconsolidated Subsidiaries are included within our consolidated U.S. tax return; therefore, the Income tax benefit line on the Consolidated Statements of Operations includes income taxes related to these entities. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further information on the Unconsolidated Subsidiaries.

We perform contemporaneous reclamation activities at each mine in the normal course of operations. Under all of the Unconsolidated Subsidiaries’ contracts, the customer has the obligation to fund final mine reclamation activities. Under certain contracts, the Unconsolidated Subsidiary holds the mine permit and is therefore responsible for final mine reclamation activities. To the extent the Unconsolidated Subsidiary performs such final reclamation, it is compensated for providing those services in addition to receiving reimbursement from customers for costs incurred.

Contract Mining Segment

The Contract Mining segment provides value-added contract mining and other services for producers of industrial minerals and products. The segment is a platform for our growth and diversification of mining activities outside of the thermal coal industry. Contract Mining provides contract mining services for independently owned mines and quarries, creating value for our customers by performing the mining aspects of our customers’ operations. This allows customers to focus on their areas of expertise: materials handling and processing, product sales and distribution. As of December 31, 2025, the Contract Mining segment operates at quarries in Florida, Arkansas and Nebraska and is expected to begin operations at a quarry in Arizona during the first half of 2026. Beginning in 2026, the Contract Mining segment will also provide dragline services as part of a U.S. Army Corps of Engineers construction project in Palm Beach County, Florida.

In addition, Contract Mining's subsidiary, Sawtooth, is the exclusive provider of comprehensive mining services for the Thacker Pass lithium project in Humboldt County, Nevada. Thacker Pass is owned by a joint venture between Lithium

Americas Corp. (TSX:LAC) (NYSE: LAC) and General Motors Holdings LLC. The U.S. Department of Energy holds warrants to purchase five percent non-voting, non-transferable equity in this joint venture. Thacker Pass is targeting initial lithium production in late 2027. The contract requires reimbursement for costs of mining, capital expenditures and mine closure. Sawtooth will recognize a contractually agreed upon production fee once the mine is operating. In addition to providing comprehensive mining services, Sawtooth is currently assisting with certain construction services and will transport clay tailings once lithium production commences.

Minerals and Royalties Segment

The Minerals and Royalties segment derives income primarily by leasing our royalty and mineral interests to third-party exploration and production companies, and, to a lesser extent, other mining companies, granting them the rights to explore, develop, mine, produce, market and sell gas, oil, and coal in exchange for royalty payments based on the lessees' sales of those minerals.

The Minerals and Royalties segment owns royalty interests, mineral interests, non-participating royalty interests and overriding royalty interests (collectively mineral and royalty interests).

•Royalty Interest. Royalty interests generally result when the owner of a mineral interest leases the underlying minerals to an exploration and production company pursuant to an oil and gas lease. Typically, the resulting royalty interest is a cost-free percentage of production revenues for minerals extracted from the acreage. A holder of royalty interests is generally not responsible for capital expenditures or lease operating expenses, but royalty interests may be calculated net of post-production expenses. Royalty interests leased to producers expire upon the expiration of the oil and gas lease and revert to the mineral owner.

•Mineral Interest. Mineral interests are perpetual rights of the owner to explore, develop, exploit, mine and/or produce any or all of the minerals lying below the surface of the property. The holder of a mineral interest has the right to lease the minerals to an exploration and production company. Upon the execution of an oil and gas lease, the lessee (the exploration and production company) becomes the working interest owner and the lessor (the mineral interest owner) has a royalty interest.

•Non-Participating Royalty Interest (NPRIs). NPRI is an interest in oil and gas production which is created from the mineral estate. The NPRI is expense-free, bearing no operational costs of production. The term non-participating indicates that the interest owner does not share in the bonus, rentals from a lease, nor the right to participate in the execution of oil and gas leases. The NPRI owner does; however, typically receive royalty payments.

•Overriding Royalty Interest (ORRIs). ORRIs are created by carving out the right to receive royalties from a working interest. Like royalty interests, ORRIs do not confer an obligation to make capital expenditures or pay for lease operating expenses and have limited environmental liability; however, ORRIs may be calculated net of post-production expenses, depending on how the ORRI is structured. ORRIs that are carved out of working interests are linked to the same underlying oil and gas lease that created the working interest, and therefore, such ORRIs are typically subject to expiration upon the expiration or termination of the oil and gas lease.

We may own more than one type of mineral and royalty interest in the same tract of land. For example, where we own an ORRI in a lease on the same tract of land in which we own a mineral interest, the ORRI in that tract will relate to the same gross acres as the mineral interest in that tract.

As of December 31, 2025 and 2024, the Minerals and Royalties segment holds an equity investment of $33.7 million and $19.1 million, respectively, in Eiger Resources, which holds operated and non-operated working interests in oil and natural gas assets in the Kansas and the Oklahoma portion of the Hugoton basin. Although we own less than 20%, Eiger Resources meets the definition of a VIE. NACCO is not the primary beneficiary of the VIE as it does not exercise financial control; therefore, we do not consolidate the results of these operations within our financial statements. Instead, this contract is accounted for as an equity method investment. Our investment is reported on the line Equity method investment in Eiger Resources in the Consolidated Balance Sheets. The Minerals and Royalties segment records its share of earnings as Earnings of unconsolidated operations on the Consolidated Statements of Operations. Due to the timing and availability of financial information, earnings or losses from this investment are recorded on a one quarter lag.

Changes in the Eiger Resources equity method investment balance are summarized as follows:

Excluding the Eiger Resources investment described above, total consideration for acquisitions of mineral and royalty interests was $4.7 million and $0.7 million, in 2025 and 2024, respectively. The 2025 acquisitions include 10.5 thousand gross acres and 0.4 thousand net royalty acres. The 2024 acquisitions included 13.7 thousand gross acres and 0.6 thousand net royalty acres.

The Minerals and Royalties segment also manages legacy royalty and mineral interests located in Ohio (Utica and Marcellus shale natural gas), Louisiana (Haynesville shale and Cotton Valley formation natural gas), Texas (Cotton Valley and Austin Chalk formation natural gas), Mississippi (coal), Pennsylvania (coal, coalbed methane and Marcellus shale natural gas), Alabama (coal, coalbed methane and natural gas) and North Dakota (coal, oil and natural gas). The majority of our legacy reserves were acquired as part of our historical coal mining operations.

Total oil and gas mineral and royalty interests include approximately 208.0 thousand gross acres and 64.4 thousand net royalty acres at December 31, 2025. Net royalty acres are calculated based on our ownership and royalty rate, normalized to a standard 1/8 th royalty lease, and assumes a 1/4 th royalty rate for unleased acres. See Note 17 for further discussion of Minerals and Royalties.

Other items: At December 31, 2025 and 2024, we had $12.8 million and $14.2 million classified as Assets held for sale on the Consolidated Balance Sheets. During 2025, we sold three draglines that were classified as Assets held for sale as of December 31, 2024 and recognized a $0.1 million gain in the Contract Mining segment, which is included on the line Gain on sale of assets within the Consolidated Statements of Operations. At December 31, 2025, Assets held for sale consists of two draglines not in use in the Contract Mining Segment and an office building in North Dakota in Unallocated Items.

During 2025, we terminated the NACCO Combined Defined Benefit Plan (Combined Plan) and settled all future obligations by transferring the remaining benefit obligations to a third-party insurance company. Although the plan was overfunded, we recognized a non-cash, pension settlement charge of $7.8 million on the line Pension settlement charge within the Consolidated Statements of Operations. The $7.8 million settlement charge accelerated the recognition of the net loss recorded in Accumulated other comprehensive loss that would have otherwise been recognized in subsequent periods. See Note 14 to the Consolidated Financial Statements in this Form 10-K for further information on the Combined Plan.

During 2025, the Company and Falkirk’s former customer agreed to settle the Falkirk Defined Benefit Plan for $10.9 million, resulting in a gain of $3.6 million on the line Gain on settlement of excess funding liability within the Consolidated Statements of Operations. In accordance with the agreement reached with the former customer, $5.5 million was paid to the former customer during 2025. The remaining $5.4 million, recorded on the line Excess funding liability on the Consolidated Balance Sheets at December 31, 2025, will be paid to the former customer in 2026.

The excess funds from the terminated Combined Plan and the Falkirk Defined Benefit Plan will be utilized by the NACCO 401(k) plan, which is a qualified replacement plan. These funds will be used for future profit sharing contributions to eligible 401(k) plan participants. Total remaining funds are $14.6 million as of December 31, 2025. The current portion of $11.5 million is recorded on the line Prepaid profit sharing and the long-term portion of $3.1 million is recorded on the line Other non-current assets on the Consolidated Balance Sheet as of December 31, 2025.

During 2024, we sold land for $7.0 million and recognized a $4.5 million gain in the Minerals and Royalties segment, which is included on the line Gain on sale of assets within the Consolidated Statements of Operations.

NOTE 2—Significant Accounting Policies

Use of Estimates: The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and judgments. These estimates and judgments affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities (if any) at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents: Cash and cash equivalents include cash in banks and highly liquid investments with original maturities of three months or less.

Property, Plant and Equipment, Net: Property, plant and equipment are initially recorded at cost. Depreciation, depletion and amortization are provided in amounts sufficient to amortize the cost of the assets, including assets recorded under finance leases, over their estimated useful lives using the straight-line method or the units-of-production method. Buildings and building improvements are depreciated over the life of the asset, which is generally 30 years. Estimated lives for machinery and equipment generally range from three to 15 years. The units-of-production method is used to amortize certain assets based on estimated recoverable tonnages. Repairs and maintenance costs are expensed when incurred, unless such costs extend the estimated useful life of the asset, in which case such costs are capitalized and depreciated. Asset retirement costs associated with asset retirement obligations are capitalized with the carrying amount of the related long-lived asset and depreciated over the asset's estimated useful life.

Royalty Interests in Oil and Natural Gas Properties: We follow the successful efforts method of accounting for royalty and mineral interests. Under this method, costs to acquire mineral and royalty interests in oil and natural gas properties are capitalized when incurred. Acquisitions of royalty interests of oil and natural gas properties are considered asset acquisitions and are recorded at cost.

Acquisition costs of proved royalty and mineral interests are amortized using the units of production method over the life of the property, which is estimated using proved reserves. For purposes of amortization, interests in oil and natural gas properties are grouped in a reasonable aggregation of properties.

We review and evaluate our royalty interests in oil and natural gas properties for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. Proved oil and gas properties are reviewed for impairment when events and circumstances indicate a potential decline in the fair value of such properties below the carrying value, such as a downward revision of the reserve estimates or lower commodity prices. When such events or changes in circumstances occur, we estimate the undiscounted future cash flows expected in connection with the properties and compare such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. If the carrying value of the properties is determined to not be recoverable based on the undiscounted cash flows, an impairment charge is recognized by comparing the carrying value to the estimated fair value of the properties.

See Note 17 for further discussion of our royalty and mineral interests.

Long-Lived Assets: We periodically evaluate long-lived assets for impairment when changes in circumstances or the occurrence of certain events indicate the carrying amount of an asset or asset group may not be recoverable. Upon identification of indicators of impairment, we evaluate the carrying value of the asset by comparing the estimated future undiscounted cash flows generated from the use of the asset or asset group and its eventual disposition with the asset's net carrying value. If the carrying value of an asset is considered impaired, an impairment charge is recorded for the amount that the carrying value of the long-lived asset or asset group exceeds its fair value. Fair value is estimated as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

Self-insurance Liabilities: We are generally self-insured for medical claims, certain workers’ compensation claims and certain closed mine liabilities. An estimated provision for claims reported and for claims incurred but not yet reported under the self-insurance programs is recorded and revised periodically based on industry trends, historical experience and management judgment. In addition, industry trends are considered within management's judgment for valuing claims. Changes in assumptions for such matters as legal judgments and settlements, inflation rates, medical costs and actual experience could cause estimates to change in the near term.

Revenue Recognition: See Note 3 to the Consolidated Financial Statements for discussion of our revenue recognition.

Stock Compensation: We maintain a long-term incentive program that allow for the grant of shares of Class A common stock, subject to restrictions, as a means of retaining and rewarding selected employees for long-term performance and to increase their ownership in NACCO. Shares awarded under the plans are fully vested and entitle the stockholder to all rights of common stock ownership except that shares may not be assigned, pledged or otherwise transferred during the restriction period. In general, for shares awarded for years ended December 31, 2025 and December 31, 2024, the restriction period ends at the earliest of (i)three years after the participant's retirement date, (ii)three, five orten years from the award date, or (iii) the participant's death or permanent disability. Pursuant to the plans, we issued 124,401 and 162,670 shares related to the years ended December 31, 2025 and 2024, respectively. After the issuance of these shares, there were 492,280 shares of Class A common stock available for issuance under these plans. Compensation expense related to these share awards was $7.1 million ($5.6 million net of tax) and $5.2 million ($4.1 million net of tax) for the years ended December 31, 2025 and 2024, respectively. Compensation expense represents fair value based on the market price of the shares of Class A common stock at the grant date.

We also have a stock compensation plan for non-employee directors under which a portion of the annual retainer for each non-employee director is paid in restricted shares of Class A common stock. For the year ended December 31, 2025, $112,000 ($195,000 for the Chairman) of the non-employee director's annual retainer of $179,000 ($300,000 for the Chairman) was paid in restricted shares of Class A common stock. For the year ended December 31, 2024, $110,000 ($150,000 for the Chairman) of the non-employee director's annual retainer of $175,000 ($250,000 for the Chairman) was paid in restricted shares of Class A common stock. Shares awarded under the plan are fully vested and entitle the stockholder to all rights of common stock ownership except that shares may not be assigned, pledged, hypothecated or otherwise transferred during the restriction period. In general, the restriction period ends at the earliest of (i)ten years from the award date, (ii) the date of the director's death or permanent disability, (iii)five years (or earlier with the approval of the Board of Directors) after the director's date of retirement from the Board of Directors, (iv) the date the director has both retired from the Board of Directors and has reached age 70, or (v) at such other time as determined by the Board of Directors in their sole and absolute discretion. Pursuant to this plan, we issued 35,372 and 44,731 shares related to the years ended December 31, 2025 and 2024, respectively. In addition to the mandatory retainer fee received in restricted stock, directors may elect to receive shares of Class A common stock in lieu of cash for up to 100% of the balance of their annual retainer, committee retainer and any committee chairman's fees. These voluntary shares are not subject to any restrictions. There wereno shares issued under voluntary elections in 2025 and 2024. After the issuance of these shares, there were 175,687 shares of Class A common stock available for issuance under this plan. Compensation expense related to these awards was $1.5 million ($1.2 million net of tax) and $1.3 million ($1.0 million net of tax) for the years ended December 31, 2025 and 2024, respectively. Compensation expense represents fair value based on the market price of the shares of Class A common stock at the grant date.

Financial Instruments: Financial instruments held by us include cash and cash equivalents, accounts receivable, equity securities, accounts payable, revolving credit agreements and long-term debt.

Fair Value Measurements: We account for the fair value measurement of our financial assets and liabilities in accordance with U.S. generally accepted accounting principles, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

A fair value hierarchy requires an entity to maximize the use of observable inputs, where available, and minimize the use of unobservable inputs when measuring fair value.

Described below are the three levels of inputs that may be used to measure fair value:

Level 1 - Quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.

Level 2 - Observable prices that are based on inputs not quoted on active markets, but corroborated by market data.

Level 3 - Unobservable inputs are used when little or no market data is available.

The hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The classification of fair value measurements within the hierarchy is based upon the lowest level of input that is significant to the measurement. See Note 9 for further discussion of fair value measurements.

Recently Issued Accounting Standards

Accounting Standards Adopted in 2025: During 2025, we adopted ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures (ASU 2023-09) on a prospective basis, which requires entities to disclose more detailed information about their effective tax rate reconciliation as well as information on income taxes paid. The adoption of this standard only impacts disclosures and did not have a material impact on our Financial Statements.

Accounting Standards Not Yet Adopted: In November 2024, the FASB issued ASU No. 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40) (ASU 2024-03), which requires entities to disclose disaggregated information about certain income statement expense line items in the notes to their financial statements on an annual and interim basis. ASU 2024-03 is effective for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. We are currently in the process of evaluating the impact of this ASU on our Financial Statements and related disclosures.

Reclassification: Certain reclassifications have been made to the prior periods’ Consolidated Financial Statements to conform to the current period's presentation.

NOTE 3—Revenue Recognition

Nature of Performance Obligations: At contract inception, we assess the goods and services promised in our contracts with customers and identify a performance obligation for each promised good or service that is distinct. To identify the performance obligations, we consider all of the goods or services promised in the contract regardless of whether they are explicitly stated or are implied by customary business practices.

Each mine or mine area has a contract with our respective customer that represents a contract under ASC 606. For our consolidated entities, our performance obligations vary by contract and consist of the following:

At MLMC, each MMBtu delivered during the production period is considered a separate performance obligation. Revenue is recognized at the point in time that control of each MMBtu of lignite transfers to the customer. Fluctuations in revenue from period to period generally result from changes in customer demand.

In the Contract Mining segment, the management service to oversee the operation of the equipment and delivery of aggregates or other minerals is the performance obligation accounted for as a series. Performance momentarily creates an asset that the customer simultaneously receives and consumes; therefore, control is transferred to the customer over time. Consistent with the conclusion that the customer simultaneously receives and consumes the benefits provided, an input-based measure of progress is appropriate. As each month of service is completed, revenue is recognized for the amount of actual costs incurred, plus the management fee or fixed fee and the general and administrative fee (as applicable). Fluctuations in revenue from period to period result from changes in customer demand primarily due to increases and decreases in activity levels on individual contracts and variances in reimbursable costs. Revenue from equipment sales and part sales is recognized upon transfer of control to the customer.

The Minerals and Royalties segment enters into contracts which grant the right to explore, develop, produce and sell minerals controlled by us. These arrangements result in the transfer of mineral rights for a period of time; however, no rights to the actual land are granted other than access for purposes of exploration, development, production and sales. The mineral rights revert back to us at the expiration of the contract.

Under these contracts, granting exclusive right, title, and interest in and to minerals, if any, is the performance obligation. The performance obligation under these contracts represents a series of distinct goods or services whereby each day of access that is provided is distinct. The transaction price consists of a variable sales-based royalty and, in certain arrangements, a fixed component in the form of an up-front lease bonus payment. As the amount of consideration we will ultimately be entitled to is entirely susceptible to factors outside of our control, the entire amount of variable consideration is constrained at contract inception. We believe that the pricing provisions of royalty contracts are customary in the industry.

Mitigation Resources provides natural resource restoration and reclamation services that include stream and wetland mitigation solutions. For restoration and reclamation services, the service contracts are generally structured as an agreement under which Mitigation Resources is reimbursed for all costs incurred plus a fixed fee. The services provided represent the performance obligation and are accounted for as a series. Performance momentarily creates an asset that the customer simultaneously receives and consumes; therefore, control is transferred to the customer as work is completed. Consistent with the conclusion that the customer simultaneously receives and consumes the benefits provided, an input-based measure of progress is appropriate. As each month of service is completed, revenue is recognized for the amount of actual costs incurred, plus the fixed fee. Fluctuations in revenue from period to period result from increases and decreases in activity levels of individual contracts and variances in reimbursable costs.

Mitigation Resources also generates and sells stream and wetland mitigation credits (known as mitigation banking). In mitigation banking, each mitigation credit sale is considered a separate performance obligation. Mitigation banks are regulated and approved by the U.S. Army Corps of Engineers and other federal, state and local agencies. Mitigation credits are released in phases over the life of the mitigation bank. Revenue is recognized at the point in time that control of each mitigation credit transfers to the customer. Fluctuations in revenue from period to period generally result from changes in timing of mitigation credit releases and/or customer demand.

Significant Judgments: The contracts with our customers in the Utility Coal Mining and Contract Mining segments contain different types of variable consideration including, but not limited to, management fees that adjust based on volumes or MMBtu delivered. However, the terms of these variable payments relate specifically to our efforts to satisfy one or more, but not all, of the performance obligations (or to a specific outcome from satisfying the performance obligations) in the contract. Therefore, we allocate each variable payment (and subsequent changes to that payment) entirely to the specific performance obligation to which it relates. Management fees, as well as general and administrative fees, are also adjusted based on changes in specified indices (e.g., CPI) to compensate for general inflation changes. Index adjustments, if applicable, are effective prospectively.

In the Minerals and Royalties segment, we have the right to receive revenues from the sale of oil and natural gas through sales of the third-party lessees in which we own a mineral or royalty interest. Revenue is recognized at the point control of the product is transferred from the operator to the purchaser. Those purchasers remit payment to the operator and the operator, in turn, remits payment to us. Receivables from third-party lessees for which we did not receive actual production information, either due to timing delays or due to the unavailability of data at the time when revenues are recognized, are estimated using expected sales volumes and estimated prices. The difference between our estimates and the actual amounts received is recorded in the month that payment is received from the third-party lessee. We typically receive payment for oil and natural gas sales within 90 days of the month of delivery. For the years ended December 31, 2025 and 2024, differences between our estimates and the actual amounts received from operators were immaterial.

Cost Reimbursement: Certain contracts include reimbursement from customers of actual costs incurred for the purchase of supplies, equipment and services in accordance with contractual terms. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof is highly dependent on factors outside of our control. Accordingly, reimbursable revenue is fully constrained and not recognized until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer with the related costs recorded as an expense within cost of sales.

At the Thacker Pass lithium project, in addition to management fee income, the customer will reimburse Sawtooth for certain capital expenditures. Sawtooth will recognize revenue over the estimated useful life of the asset on a straight-line basis as the performance obligation is satisfied over time. In prior years, the customer received a $3.5 million advance from Sawtooth, which is included in the long-term contract asset. The customer will pay a $4.7 million success fee to Sawtooth if commercial mining milestones are met, at which time Sawtooth will recognize the revenue for the difference between the success fee and the amount advanced. If commercial mining milestones are not met, the customer will only repay the $3.5 million advance.

Prior Period Performance Obligations: As discussed above, we record royalty income in the month production is delivered to the purchaser. The expected sales volumes and prices for these properties are estimated and recorded in Other current assets in the Consolidated Balance Sheets. The difference between our estimates and the actual amounts received is recorded in the month that payment is received from the third-party lessee. During the years ended December 31, 2025 and 2024, royalty income recognized in the reporting period relating to production satisfied in prior periods was $1.5 million andimmaterial, respectively.

Disaggregation of Revenue: In accordance with ASC 606-10-50, we disaggregate revenue from contracts with customers into major goods and service lines and timing of transfer of goods and services. We determined that disaggregating revenue into these categories achieves the disclosure objective of depicting how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. Our business consists of the Utility Coal Mining, Contract Mining and Minerals and Royalties segments as well as Unallocated Items. Revenue included in Unallocated Items is primarily related to Mitigation Resources. See Note 15 to the Consolidated Financial Statements for further discussion of segment reporting.

The following table disaggregates revenue by major sources for the years ended December 31:

Contract Balances

The opening and closing balances of our current and long-term contract assets and liabilities and receivables are as follows:

We expect to recognize $1.4 million in 2026, $0.3 million in 2027, $1.2 million in 2028, $0.2 million in 2029 and 2030 and $8.7 million thereafter related to the contract liability remaining at December 31, 2025. The difference between the opening and closing balances of our contract balances results from the timing difference between our performance and the customer’s payment.

We haveno contract assets recognized from the costs to obtain or fulfill a contract with a customer.

NOTE 4—Inventories

Inventories are summarized as follows:

The weighted average method is used for inventory valuation. During the year ended December 31, 2025 and 2024, we recorded $7.0 million and $9.6 million of inventory impairment charges, respectively, in the line Cost of sales in the Consolidated Statements of Operations as mining costs exceeded net realizable value of coal inventory at MLMC.

Mining supplies inventory consists primarily of critical spare parts to support Contract Mining’s dragline operations and other general supplies used on day-to-day operations. Mining supplies inventory not expected to be utilized within the next 12 months is classified as long-term on the Consolidated Balance Sheet.

NOTE 5—Property, Plant and Equipment, Net

Property, plant and equipment, net includes the following:

Total depreciation, depletion and amortization expense on property, plant and equipment was $24.5 million and $24.1 million during 2025 and 2024, respectively.

NOTE 6—Intangible Assets

We have a coal supply agreement intangible asset which is subject to amortization based on units of production over the term of the lignite sales agreement which expires in 2032. The gross and net balances are set forth in the following table:

Amortization expense for intangible assets was $0.8 million and $0.5 million in 2025 and 2024, respectively.

NOTE 7—Asset Retirement Obligations

Our obligations associated with the retirement of long-lived assets are recognized at fair value at the time the legal obligations are incurred. Upon initial recognition of a liability, a corresponding amount is capitalized as part of the carrying value of the related long-lived asset within Property, Plant and Equipment, net in the Consolidated Balance Sheets. The asset is depreciated either by the straight-line method or the units-of-production method. The liability is accreted each period until the liability is settled, at which time the liability is removed. The depreciation of the asset and the accretion of the liability are both recorded in the line Cost of sales in the Consolidated Statements of Operations. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Our asset retirement obligations are principally for costs to close our consolidated surface mines and reclaim the land as a result of our normal mining activities. Management’s estimate involves a high degree of subjectivity. In particular, the obligation’s fair value is determined using a discounted cash flow technique and is based upon mining permit requirements and various assumptions including credit adjusted risk-free-rates, estimates of disturbed acreage, life of the mine, estimated reclamation costs, the application of various environmental laws and regulations and assumptions regarding equipment productivity. We review our asset retirement obligations at each mine site at least annually and makes necessary adjustments for permit changes and for revisions of estimates of the timing and extent of reclamation activities and cost estimates.

A reconciliation of our beginning and ending aggregate carrying amount of the asset retirement obligations are as follows:

Bellaire's legacy liabilities include obligations for water treatment and other environmental remediation that arose as part of the normal course of closing these underground mining operations. Since Bellaire's properties are no longer active operations, no associated asset has been capitalized. Bellaire’s asset retirement obligation is included in the table above in the Unallocated Items column.

In a previous period, Bellaire established a $5.0 million Mine Water Treatment Trust, which is legally restricted for purposes of settling the Bellaire asset retirement obligation, to assure the long-term treatment of post-mining discharges. The fair value of Bellaire's Mine Water Treatment assets are $13.5 million and $12.3 million at December 31, 2025 and December 31, 2024, respectively, and is recognized as a component of Equity securities in the Consolidated Balance Sheets. See Note 9 for further discussion of the Mine Water Treatment Trust.

NOTE 8—Current and Long-Term Financing

Financing arrangements are obtained and maintained at the subsidiary level. NACCO has not guaranteed any borrowings of our subsidiaries. The following table summarizes our available and outstanding borrowings:

Annual maturities of total debt, excluding leases, are as follows:

Interest paid on total debt was $7.0 million and $5.3 million during 2025 and 2024, respectively. Interest capitalized was $1.5 million during 2025.

In September 2024, NACCO Natural Resources amended its secured revolving line of credit (Facility) to increase the revolving credit commitments to $200.0 million and extend the maturity to September 2028. Borrowings outstanding under the Facility were $75.0 million at December 31, 2025. At December 31, 2025, the excess availability under the Facility was $74.5 million, which reflects a reduction for outstanding letters of credit of $50.5 million.

The Facility has performance-based pricing, which sets interest rates based upon NACCO Natural Resources achieving various levels of debt to EBITDA ratios, as defined in the Facility. Borrowings bear interest at a floating rate plus a margin based on the level of debt to EBITDA ratio achieved. The applicable margins, effective December 31, 2025, for base rate and Term Secured Overnight Financing Rate loans were 1.50% and 2.50%, respectively. The Facility has a commitment fee which is based upon achieving various levels of net debt to EBITDA ratios. The commitment fee was 0.40% on the unused commitment at December 31, 2025. During the year ended December 31, 2025 and December 31, 2024, the average borrowing under the Facility was $57.3 million and $27.2 million, respectively, and the weighted-average annual interest rate, including the floating rate margin, was 7.21% and 8.83%, respectively.

The Facility contains restrictive covenants, which require, among other things, NACCO Natural Resources to maintain a maximum net debt to EBITDA ratio of 2.75 to 1.00 and an interest coverage ratio of not less than 4.00 to 1.00. The Facility provides the ability to make loans, dividends and advances to NACCO, with some restrictions based on maintaining a maximum debt to EBITDA ratio of 1.50 to 1.00, or if greater than 1.50 to 1.00, a Fixed Charge Coverage Ratio of 1.10 to 1.00. At December 31, 2025, NACCO Natural Resources was in compliance with all financial covenants in the Facility.

The obligations under the Facility are guaranteed by certain of NACCO Natural Resources' direct and indirect, existing and future domestic subsidiaries, and is secured by certain assets of NACCO Natural Resources and the guarantors, subject to customary exceptions and limitations.

We have a demand note payable to Coteau, one of the unconsolidated subsidiaries, which bears interest based on the applicable quarterly federal short-term interest rate as announced from time to time by the IRS. At December 31, 2025 and 2024, the balance of the note was $7.3 million and $7.7 million and the interest rate was 3.75% and 4.15%, respectively.

We haveten notes payable that are secured bytwelve specified units of equipment, bear interest at a weighted average rate of 5.48%, and expire at various dates through 2030. One note includes a principal payment of $4.4 million at the end of the term on December 15, 2026. At December 31, 2025 and 2024, the outstanding balances of the notes payable were $18.5 million and $21.8 million, respectively.

NOTE 9—Fair Value Disclosure

Recurring Fair Value Measurements: The following table presents our assets accounted for at fair value on a recurring basis:

Bellaire's Mine Water Treatment Trust invests in equity securities that are reported at fair value based upon quoted market prices in active markets for identical assets; therefore, they are classified as Level 1 within the fair value hierarchy. The fair value of the Mine Water Treatment Trust was $13.5 million and $12.3 million at December 31, 2025 and December 31, 2024, respectively, and is recognized as a component of Equity securities in the Consolidated Balance Sheets. We recognized gains of $1.4 million and $1.5 million in the years ended December 31, 2025 and 2024, respectively, related to the Mine Water Treatment Trust. See Note 7 for further discussion of Bellaire's Mine Water Treatment Trust.

In a previous period, we invested $2.0 million in equity securities of a public company with a diversified portfolio of royalty producing mineral interests. The investment is reported at fair value based upon quoted market prices in active markets for identical assets; therefore, it is classified as Level 1 within the fair value hierarchy. The fair value of this investment was $4.2 million and $6.3 million at December 31, 2025 and December 31, 2024, respectively, and is recognized as a component of Equity securities in the Consolidated Balance Sheets. We recognized a loss of $2.1 million and a gain of $0.3 million in the years ended December 31, 2025 and 2024, respectively, related to the investment in these equity securities.

The change in fair value of equity securities is reported on the line Loss (gain) on equity securities in the Other expense (income) section of the Consolidated Statements of Operations.

In 2025, excess funds from the terminated Combined Plan and the Falkirk Defined Benefit Plan were transferred to a separate investment account. These funds will be utilized for future profit sharing contributions to eligible 401(k) plan participants. The Prepaid profit sharing balance is reported at fair value based upon quoted market prices in active markets for identical assets; therefore, it is classified as Level 1 within the fair value hierarchy. See Note 1 for further discussion of the Prepaid profit sharing balance.

There were no transfers into or out of Levels 1, 2 or 3 during the years ended December 31, 2025 and 2024.

Other Fair Value Measurement Disclosures: The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these instruments. The fair values of revolving credit agreements and long-term debt, excluding finance leases, were determined using current rates offered for similar obligations taking into account subsidiary credit risk, which is Level 2 as defined in the fair value hierarchy. The fair value and the book value of revolving credit agreements and long-term debt, excluding finance leases, was $100.1 million and $100.8 million, respectively, at December 31, 2025 and $97.9 million and $99.4 million, respectively, at December 31, 2024.

Financial instruments that potentially subject us to concentration of credit risk consist principally of accounts receivable. Under our mining contracts, we recognize revenue and a related receivable as coal or other aggregates are delivered or predevelopment services are provided. These mining contracts generally provide for settlements within 60 days. Our significant credit concentration is uncollateralized; however, historically minimal credit losses have been incurred. To further reduce credit risk associated with accounts receivable, we perform periodic credit evaluations of our customers, but do not generally require advance payments or collateral.

NOTE 10—Leases

We recognize right-of-use assets (ROU assets) and lease liabilities for operating leases of real estate, mining and other equipment that expire at various dates through 2036. The majority of our leases are operating leases. NACCO does not recognize leases with a term of 12 months or less on the balance sheet. Instead, we recognize the related lease expense on a straight-line basis over the lease term. We account for lease and non-lease components as a single lease component. Our lease agreements do not contain lease payments that depend on an index or a rate, as such, minimum lease payments do not include variable lease payments.

Leased assets and liabilities include the following at December 31:

(a)Finance leased assets are recorded net of accumulated amortization of less than $0.1 million as of December 31, 2025 and December 31, 2024.

The components of lease expense for the years ended December 31 are as follows:

Future minimum finance and operating lease payments were as follows at December 31, 2025:

As most of our leases do not provide an implicit rate, we determine the incremental borrowing rate based on the information available at the lease commencement date in determining the present value of lease payments. We consider our credit rating and the current economic environment in determining this collateralized rate. The assumptions used in accounting for ASC 842 for the years ended December 31 are as follows:

The following table details cash paid for amounts included in the measurement of lease liabilities for the years ended December 31:

NOTE 11—Contingencies

Various legal and regulatory proceedings and claims have been or may be asserted against NACCO and certain subsidiaries relating to the conduct of their businesses. These proceedings and claims are incidental to the ordinary course of our business. Management believes that it has meritorious defenses and will vigorously defend us in these actions. Any costs that management estimates will be paid as a result of these claims are accrued when the liability is considered probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not accrue liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is probable or reasonably possible and which are material, we disclose the nature of the contingency and, in some circumstances, an estimate of the possible loss.

These matters are subject to inherent uncertainties, and unfavorable rulings could occur. If an unfavorable ruling were to occur, there exists the possibility of an adverse impact on our financial position, results of operations and cash flows of the period in which the ruling occurs, or in future periods.

NOTE 12—Stockholders' Equity and Earnings Per Share

NACCO Industries, Inc. Class A common stock is traded on the New York Stock Exchange under the ticker symbol NC. Because of transfer restrictions on Class B common stock, no trading market has developed, or is expected to develop, for our Class B common stock. The Class B common stock is convertible into Class A common stock on a one-for-one basis at any time at the request of the holder. Our Class A common stock and Class B common stock have the same cash dividend rights per share. As the liquidation and dividend rights are identical, any distribution of earnings would be allocated to Class A and Class B stockholders on a proportionate basis, and accordingly the net income per share for each class of common stock is identical. The Class A common stock hasone vote per share and the Class B common stock hasten votes per share. The total number of authorized shares of Class A common stock and Class B common stock at December 31, 2025 was 25,000,000 shares and 6,756,176 shares, respectively. Treasury shares of Class A common stock totaling 2,356,755 and 2,488,013 at December 31, 2025 and 2024, respectively, have been deducted from shares outstanding.

Stock Repurchase Program: On November 18, 2025, our Board of Directors approved a stock purchase program (2025 Stock Repurchase Program) providing for the purchase of up to $20.0 million of our outstanding Class A common stock through December 31, 2027. NACCO's previous repurchase program would have expired on December 31, 2025 but was terminated and replaced by the 2025 Stock Repurchase Program. During 2025, we repurchased 61,554 shares of Class A Common Stock for an aggregate purchase price of $2.5 million. During 2024, we repurchased 316,950 shares of Class A Common Stock for an aggregate purchase price of $9.9 million.

The timing and amount of any repurchases under the 2025 Stock Repurchase Program are determined at the discretion of our management based on a number of factors, including the availability of capital, other capital allocation alternatives, market conditions for our Class A common stock and other legal and contractual restrictions. The 2025 Stock Repurchase Program does not require us to acquire any specific number of shares and may be modified, suspended, extended or terminated by us without prior notice and may be executed through open market purchases, privately negotiated transactions or otherwise. All or part of the repurchases under the 2025 Stock Repurchase Program may be implemented under a Rule 10b5-1 trading plan, which would allow repurchases under pre-set terms at times when we might otherwise be restricted from doing so under applicable securities laws.

Stock Compensation: See Note 2 for a discussion of our restricted stock awards.

Earnings per Share: The weighted average number of shares of Class A common stock and Class B common stock outstanding used to calculate basic and diluted earnings per share were as follows:

NOTE 13—Income Taxes

We provide for income taxes and the related accounts under the asset and liability method. Deferred tax assets and liabilities are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates expected to be in effect during the year in which the basis differences reverse. Valuation allowances are established when management determines it is more likely than not that some portion, or all, of the deferred tax assets will not be realized.

The components of Income before income tax benefit and the Income tax benefit for the years ended December 31 are as follows:

Cash paid for income taxes (net of refunds) were as follows:

We made income tax payments of $5.2 million and received income tax refunds of $1.0 million during 2024.

The provision for income taxes differs from the amount computed by applying the statutory federal income tax rate to income before the provision for income taxes. A reconciliation of the federal statutory and effective income tax rate, applying ASU 2023-09 prospectively, for the year ended December 31 is as follows:

(a)During the year ended December 31, 2025, state taxes in Louisiana, North Dakota, Mississippi and Pennsylvania made up the majority of the tax effect in this category.

The reconciliation from the statutory federal income tax rate to our effective income tax rate, applying ASC 740 prior to the adoption of ASU 2023-09, is as follows:

We recorded an income tax benefit of $4.4 million for the year ended December 31, 2025 on income before income tax of $13.1 million, or (33.7)%, compared to an income tax benefit of $0.1 million on income before income tax of $33.6 million, or (0.3)%, for the year ended December 31, 2024. The years ended December 31, 2025 and 2024 included $1.9 million and $4.0 million of discrete tax benefits, primarily for deferred tax adjustments and the reversal of uncertain tax provisions, respectively. Excluding the respective $1.9 million and $4.0 million of discrete tax benefits, the effective income tax rate was (19.5)% and 11.5% in 2025 and 2024, respectively.

The change in the effective income tax rate for 2025 compared to 2024, excluding the impact of discrete items, is primarily due to an increase in losses at entities that do not benefit from percentage depletion. Losses generated by these entities generate tax deductions at the statutory rate. This shift in the mix of pre-tax income resulted in a benefit tax rate in 2025. In addition, the benefit from percentage depletion is not directly related to the amount of pre-tax income recorded in a period. Accordingly, in periods where income or loss before income tax is relatively small, the proportional effect of the benefit from percentage depletion on the effective tax rate may be significant. When income tax expense is recorded, the benefit from percentage depletion decreases the effective income tax rate, while the effect is to increase the effective income tax rate when a benefit for income taxes is recorded.

A detailed summary of the total deferred tax assets and liabilities in our Consolidated Balance Sheets resulting from differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes is as follows:

The following table summarizes the tax carryforwards and associated carryforward periods and related valuation allowances where we have determined that realization is uncertain:

We have a valuation allowance for certain state and foreign deferred tax assets. Based upon the review of historical earnings and the relevant expiration of carryforwards, including utilization limitations in the various state taxing jurisdictions, we believe the valuation allowances are appropriate and do not expect to release valuation allowances within the next twelve months that would have a significant effect on our financial position or results of operations.

Since 2021, we have participated in a voluntary program with the IRS called Compliance Assurance Process (CAP). The objective of CAP is to contemporaneously work with the IRS to achieve federal tax compliance and resolve all or most issues prior to the filing of the tax return. In general, we operate in taxing jurisdictions that provide a statute of limitations period ranging from three to five years for the taxing authorities to review the applicable tax filings. Our tax returns are under routine examination by various taxing authorities. We have not been informed of any material assessment for which an accrual has not been previously provided and would vigorously contest any material assessment. Management believes any potential adjustment would not materially affect our financial condition or results of operations.

The following is a reconciliation of our total gross unrecognized tax benefits, defined as the aggregate tax effect of differences between tax return positions and the benefits recognized in the financial statements for the years ended December 31, 2025 and 2024. Approximately $0.6 million of the gross unrecognized tax benefits as of December 31, 2025 and 2024 relate to permanent items that, if recognized, would impact the effective income tax rate. This amount differs from the gross unrecognized tax benefits presented in the table below due to (1) the deferred tax asset which would be available if the position were not sustained upon audit and (2) the decrease in U.S. federal income taxes which would occur upon the recognition of the state tax benefits included herein.

We record interest and penalties on uncertain tax positions as a component of the income tax provision. We recognized a net benefit of less than $0.1 million in interest and penalties related to uncertain tax positions during 2025 and 2024. The total amount of interest and penalties accrued was less than $0.1 million and $0.2 million as of December 31, 2025 and 2024, respectively.

We expect the amount of unrecognized tax benefits will change within the next 12 months; however, the change is not expected to have a significant effect on our financial position, results of operations or cash flows.

NOTE 14—Retirement Benefit Plans

Defined Benefit Plans: During 2025, we terminated the Combined Plan and settled all future obligations by transferring the remaining benefit obligations to a third-party insurance company. The $8.3 million in excess funds from the Combined Plan will be utilized by the NACCO 401(k) plan, which is a qualified replacement plan. These funds will be used for future profit sharing contributions to eligible 401(k) plan participants. The current portion of $5.2 million is recorded on the line Prepaid profit sharing and the long-term portion of $3.1 million is recorded on the line Other non-current assets on the Consolidated Balance Sheets as of December 31, 2025. Although the Combined Plan was over funded, we recognized a non-cash pension settlement charge of $7.8 million on the Pension settlement charge line within the Consolidated Statements of Operations. The $7.8 million settlement charge accelerated the recognition of the net loss recorded in Accumulated other comprehensive loss that would have otherwise been recognized in subsequent periods.

As of December 31, 2025, we continue to maintain a Supplemental Retirement Benefit Plan (SERP) that provides benefits based on years of service and average compensation during certain periods. In a previous period, the SERP was amended to freeze all pension benefits. The SERP pays monthly benefits to participants directly out of corporate funds.

The assumptions used in accounting for the defined benefit plans were as follows for the years ended December 31:

Set forth below is detail of the net periodic pension expense for the defined benefit plans for the years ended December 31:

Set forth below is detail of other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss for the years ended December 31:

The following table sets forth the changes in the benefit obligation and the plan assets during the year and the funded status of the defined benefit plans at December 31:

Future SERP payments are expected to be $0.5 million per year through 2027, $0.4 million in 2028 through 2030 and $1.5 million in the five years thereafter.

Postretirement Health Care: We maintain health care plans which provide benefits to grandfathered eligible retired employees. All of our health care plans have a cap on our share of the costs. The health care plans have network provided benefits which result in cost savings for us. These plans have no assets. Plan benefits are funded at the time they are due to participants.

The assumptions used in accounting for the postretirement health care plans are set forth below for the years ended December 31:

Set forth below is detail of the net periodic benefit expense for the postretirement health care plans for the years ended December 31:

Set forth below is detail of other changes in benefit obligations recognized in other comprehensive loss (income) for the years ended December 31:

The following sets forth the changes in benefit obligations during the year and the funded status of the postretirement health care plans at December 31:

Future postretirement health care benefit payments are expected to be approximately $0.2 million per year through 2030 and $0.6 million in the five years thereafter.

Defined Contribution Plans: We maintain a defined contribution (401(k)) plan for substantially all employees and provide employer matching contributions based on plan provisions. The plan also provides for a minimum employer contribution. Our matching contributions for these plans were $3.9 million and $3.6 million in 2025 and 2024, respectively.

NOTE 15—Business Segments

Our operating segments are: (i) Utility Coal Mining, (ii) Contract Mining and (iii) Minerals and Royalties. We determine our reportable segments by first identifying our operating segments, and then by assessing whether any components of these segments constitute a business for which discrete financial information is available and where segment management regularly reviews the operating results of that component. Our President and Chief Executive Officer, who is the Chief Operating Decision Maker (CODM), utilizes Operating profit (loss) to evaluate segment performance and allocate resources. Our CODM considers actual, budgeted and forecasted Operating profit (loss) from operations on a monthly basis for evaluating the performance of each segment and making decisions about allocating capital and other resources to each segment.

All financial statement line items below operating profit (other income including interest expense and interest income, the provision (benefit) for income taxes and net income) are presented and discussed within this Form 10-K on a consolidated basis.

See Note 1 for additional discussion of our reportable segments. All current operations reside in the U.S. The accounting policies of the reportable segments are described in Note 2.

In both 2025 and 2024, three customers accounted for 10% or more of consolidated revenue. The following represents the revenue attributable to each of these entities as a percentage of consolidated revenue for those years:

The following tables provide segment financial information and a reconciliation of segment results to consolidated results for the years ended December 31:

*Operating expenses consist of Selling, general and administrative expenses, Amortization of intangible assets and Gain on sale of assets.

**Unallocated Items consist primarily of Cash and cash equivalents, assets of growth businesses, Deferred income taxes and Investments in unconsolidated subsidiaries.

NOTE 16—Unconsolidated Subsidiaries

Each of our wholly owned Unconsolidated Subsidiaries, within the Utility Coal Mining and Contract Mining segments, meet the definition of a VIE. The Unconsolidated Subsidiaries are capitalized primarily with debt financing provided by or supported by their respective customers, and generally without recourse to us. Although we own 100% of the equity and manage the daily operations of the Unconsolidated Subsidiaries, we have determined that the equity capital provided by us is not sufficient to adequately finance the ongoing activities or absorb any expected losses without additional support from the customers. The customers have a controlling financial interest and have the power to direct the activities that most significantly affect the economic performance of the entities. As a result, we are not the primary beneficiary and therefore do not consolidate these entities' financial positions or results of operations. See Note 1 for a discussion of these entities.

The Investment in the unconsolidated subsidiaries and related tax positions totaled $14.8 million and $14.1 million at December 31, 2025 and 2024, respectively. Our risk of loss relating to these entities is limited to our invested capital, which was $6.7 million and $5.5 million at December 31, 2025 and 2024, respectively.

NACCO Natural Resources is a party to certain guarantees related to Coyote Creek. Under certain circumstances of default or termination of Coyote Creek’s Lignite Sales Agreement (LSA), NACCO Natural Resources would be obligated to pay a make- whole amount to Coyote Creek’s third-party lenders. The make-whole amount is based on the excess, if any, of the discounted value of the remaining scheduled debt payments over the principal amount. In addition, in the event Coyote Creek’s LSA is terminated by Coyote Creek’s customers, NACCO Natural Resources is obligated to purchase Coyote Creek’s dragline and rolling stock for the then net book value of those assets. To date, no payments have been required from NACCO Natural Resources since the inception of these guarantees. We believe that the likelihood NACCO Natural Resources would be required to perform under the guarantees is remote, and no amounts related to these guarantees have been recorded.

Summarized financial information for the Unconsolidated Subsidiaries is as follows:

Revenue includes all mine operating costs that are reimbursed by the customers of the Unconsolidated Subsidiaries as well as the compensation per ton of coal, heating unit (MMBtu) or ton of limestone delivered. Reimbursed costs have offsetting expenses and have no impact on income before income taxes. Income before income taxes represents the Earnings of the unconsolidated operations within the Utility Coal Mining and Contract Mining segments.

We received dividends of $51.5 million and $48.8 million from the Unconsolidated Subsidiaries in 2025 and 2024, respectively.

NOTE 17—Supplemental Oil and Gas Disclosures (Unaudited)

The Minerals and Royalties segment derives income primarily by leasing our royalty and mineral interests to third-party exploration and production companies, and, to a lesser extent, other mining companies, granting them the rights to explore, develop, mine, produce, market and sell gas, oil and coal in exchange for royalty payments based on the lessees' sales of those minerals. As an owner of royalty and mineral interests, our access to information concerning activity and operations of our royalty and mineral interests is limited. We do not have information that would be available to a company with working interests in oil and natural gas operations because detailed information is not generally available to owners of royalty and mineral interests. See Note 1, Note 2 and Note 15 for additional discussion of the Minerals and Royalties segment.

Capitalized Oil and Natural Gas Costs: Aggregate capitalized costs related to oil and gas royalty and mineral interests with applicable accumulated depreciation, depletion and amortization at December 31 are as follows:

Oil and Natural Gas Reserves: Total net proved reserves are defined as those natural gas and hydrocarbon liquid reserves to Company interests after deducting all royalties, overriding royalties, and reversionary interests owned by outside parties that become effective upon payout of specified monetary balances. Decline curve analysis was used to estimate the remaining reserves of pressure depletion reservoirs with enough historical production data to establish decline trends. Reservoirs under non-pressure depletion drive mechanisms and non-producing reserves were estimated by volumetric analysis, research of analogous reservoirs, or a combination of both. Reserves have been estimated using deterministic and probabilistic methods. All reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry and conform to guidelines developed and adopted by the SEC.

The following table presents our estimated net proved oil and natural gas reserves as of December 31 based on the reserve report prepared by Haas & Cobb Petroleum Consultants, our independent petroleum engineering firm. All of our reserves are located in the United States.

Estimated Proved Reserves: The following table summarizes changes in proved reserves during the year ended December 31, 2025:

Estimated Proved Undeveloped Reserves (PUDs): The following table summarizes changes in PUDs during the year ended December 31, 2025:

(3) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.

As an owner of mineral and royalty interests, we generally do not have evidence of approval of operators’ development plans. As a result, proved undeveloped reserve estimates are limited to those relatively few locations for which drilling permits have been publicly filed. As of December 31, 2025, PUD reserves consists of 126 wells in various stages of drilling or completions. As of December 31, 2025, approximately 2% of our total proved reserves were classified as PUDs.

Standardized Measure of Discounted Future Net Cash Flows: Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted average of first-day-of-the-month commodity prices for the periods presented. Future cash inflows are computed by applying applicable prices relating to proved reserves to the year-end quantities of those reserves. Future production and costs are derived based on current costs assuming continuation of existing economic conditions. Federal income tax expenses are deducted from future production revenues in the calculation of the standardized measure using the statutory tax rate. We are subject to certain state-based taxes; however, these amounts are not material. The projections should not be viewed as realistic estimates of future cash flows, nor should the standardized measure be interpreted as representing current value to us. 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 realized are expected to vary significantly from those used; and actual costs may vary.

The following table provides the future net cash flows relating to proved oil and gas reserves based on the standardized measure of discounted cash flows as of December 31, 2025:

The following table provides the future net cash flows relating to proved oil and gas reserves based on the standardized measure of discounted cash flows as of December 31, 2024:

The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows during 2025:

(3) Requirements for oil and gas reserve estimation and disclosure require that reserve estimates and future cash flows be based on the average market prices for sales of oil and gas on the first calendar day of each month during the year. The benchmark price for WTI crude oil sold at Cushing, OK during 2025 and 2024 was $65.34 and $75.48 per bbl, respectively. The benchmark price for natural gas delivered at Henry Hub during 2025 and 2024 was $3.39 and $2.13 per MMBTU, respectively. Actual future prices and costs are likely to be substantially different from historical prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

(4) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.