NACCO Industries (NC) 10-Q2023 Q2 Quarterly report

Securities registered pursuant to Section 12(b) of the Act

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act

Number of shares of Class B Common Stock outstanding at July 28, 2023: 1,565,829

See notes to Unaudited Condensed Consolidated Financial Statements.

See notes to Unaudited Condensed Consolidated Financial Statements.

See notes to Unaudited Condensed Consolidated Financial Statements.

See notes to Unaudited Condensed Consolidated Financial Statements.

The Company also has items not directly attributable to a reportable segment. Intercompany accounts and transactions are eliminated in consolidation.

The Company’s operating segments are further described below:

The Coal Mining segment, operating as North American Coal, LLC ("NACoal"), operates surface coal mines under long-term contracts with power generation companies pursuant to a service-based business model. Coal is surface mined in North Dakota and Mississippi. Each mine is fully integrated with its customer's operations.

During the three and six months ended June 30, 2023, the 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”).

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 in the first quarter of 2023 and final reclamation began on April 1, 2023. Funding for mine reclamation is the responsibility of SWEPCO, and Sabine receives compensation for providing mine reclamation services.

At Coteau, Coyote Creek and Falkirk, the Company is 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. The customers are responsible for funding all mine operating costs, including final mine reclamation, and directly or indirectly provide all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations while providing 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 the Company. See Note 6 for further discussion of Coyote Creek's guarantees.

Coteau, Coyote Creek, Falkirk and Sabine meet the definition of a variable interest entity ("VIE"). In each case, NACCO is not the primary beneficiary of the VIE as it does not exercise financial control; therefore, NACCO does not consolidate the results of these operations within its financial statements. Instead, these contracts are accounted for as equity method investments. The income before income taxes associated with these VIEs is reported as Earnings of unconsolidated operations on the Unaudited Condensed Consolidated Statements of Operations and the Company’s investment is reported on the line Investments in unconsolidated subsidiaries in the Unaudited Condensed 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 the NACCO consolidated U.S. tax return; therefore, the Income tax (benefit) provision line on the Unaudited Condensed Consolidated Statements of Operations includes income taxes related to these entities. See Note 6 for further information on the Unconsolidated Subsidiaries.

The Company performs 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.

The MLMC contract is the only operating coal contract in which the Company is responsible for all operating costs, capital requirements and final mine reclamation; therefore, MLMC is consolidated within NACCO’s 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. Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred. As diesel fuel is heavily weighted among the indices used to determine the coal sales price, fluctuations in diesel fuel prices can result in significant fluctuations in earnings at MLMC.

The NAMining segment provides value-added contract mining and other services for producers of industrial minerals. The segment is a platform for the Company’s growth and diversification of mining activities outside of the thermal coal industry. NAMining provides contract mining services for independently owned mines and quarries, creating value for its customers by performing the mining aspects of its customers’ operations. This allows customers to focus on their areas of expertise: materials handling and processing, product sales and distribution. As of June 30, 2023, NAMining operates in Florida, Texas, Arkansas, Indiana, Virginia and Nebraska. Sawtooth Mining, LLC ("Sawtooth") provides comprehensive mining services as the exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

Certain of the entities within the NAMining segment are VIEs and are accounted for under the equity method as Unconsolidated Subsidiaries. See Note 6 for further discussion.

The Minerals Management segment derives income primarily by leasing its 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 Management segment owns royalty interests, mineral interests, non-participating royalty interests and overriding royalty interests.

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

The Minerals Management segment will benefit from the continued development of its mineral properties without the need for investment of additional capital once mineral and royalty interests have been acquired. The Minerals Management segment does not currently have any material investments under which it would be required to bear the cost of exploration, production or development.

The Company 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 the Company’s legacy reserves were acquired as part of its historical coal mining operations.

The Company recognized a gain of $30.9 million within the accompanying Unaudited Condensed Consolidated Statements of Operations during the second quarter of 2022 as GRE paid $14.0 million in cash, as well as transferred ownership of an office building with an estimated fair value of $4.1 million, and conveyed membership units in Midwest AgEnergy Group, LLC (“MAG”), a North Dakota-based ethanol business, with an estimated fair value at the transfer date of $12.8 million.

Prior to receiving the membership units from GRE, the Company held a $5.0 million investment in MAG carried at cost, less impairment. Subsequent to the receipt of the additional membership units, the Company began to account for the investment under the equity method of accounting. On December 1, 2022, the Company transferred its ownership interest in Midwest AgEnergy, LLC to HLCP Ethanol Holdco, LLC (“HLCP”) and received a cash payment of $18.6 million during the fourth quarter of 2022. The Company received a payment of $1.2 million in the first quarter of 2023 in connection with a post-closing purchase price adjustment, which is included on the line "Other, net" within the accompanying Unaudited Consolidated Statements of Operations.

The HLCP acquisition agreement includes two contingent earn-out arrangements under which additional payments are possible. The first earn-out is based on the achievement of EBITDA targets through December 31, 2024. The second earn-out is based on the development of a carbon dioxide pipeline that will support a carbon dioxide sequestration project over a four-year period commencing on the transaction closing date. Additional payments to NACCO could range from $0 to approximately $12.9 million based on achievement of the two earn-outs as well as payment of amounts held in escrow to address potential indemnity claims during the 12-month period following the transaction date. Any future payments associated with the earn-outs or amounts held in escrow will be recognized when realized, consistent with the accounting for gain contingencies.

During the first quarter of 2023, the Company’s wholly-owned subsidiary, Caddo Creek Resources Company (“Caddo Creek”), acquired 100% of the membership interests in the Marshall Mine located outside of Marshall, Texas from Advanced Emissions Solutions (“ADES”). Prior to the acquisition, Caddo Creek was performing mine reclamation under a fixed price contract with ADES. The Company received $2.2 million of cash, assumed the asset retirement obligation estimated to be approximately $1.9 million and recognized a gain of approximately $0.3 million in the first quarter of 2023.

The balance sheet at December 31, 2022 has been derived from the audited financial statements at that date but does not include all of the information or notes required by U.S. GAAP for complete financial statements.

At contract inception, the Company assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promised good or service that is distinct. To identify the performance obligations, the Company considers all of the goods or services promised in the contract regardless of whether they are explicitly stated or are implied by customary business practices.

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.

At NAMining, the management service is primarily 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 part sales is recognized upon transfer of control of the parts to the customer.

The Minerals Management segment enters into contracts which grant third-party lessees the right to explore, develop, produce and sell minerals controlled by the Company. 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 the Company at the expiration of the contract.

Mitigation Resources generates and sells stream and wetland mitigation credits (known as mitigation banking) and provides services to those engaged in permittee-responsible stream and wetland mitigation. Each mitigation credit sale is considered a separate performance obligation. 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 customer demand. Under the permittee-responsible stream and wetland mitigation model, the contracts are generally structured as agreements under which Mitigation Resources is reimbursed for all costs incurred in performing the required mitigation plus an agreed profit percentage or a fixed fee. The mitigation services provided is the performance obligation and is 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 management fee or fixed fee. Fluctuations in revenue from period to period result from changes in customer demand primarily due to increases and decreases in activity levels of individual contracts and variances in reimbursable costs.

The Company’s contracts with its customers 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 the Company's 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, the Company allocates 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.

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 the Company’s 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. The Company is considered a principal in such transactions and records the associated revenue at the gross amount billed to the customer with the related costs recorded as an expense within cost of sales.

The Company records royalty income in the month production is delivered to the purchaser. As a non-operator, the Company has limited visibility into when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser of the product and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded in "Trade accounts receivable" in the accompanying Unaudited Condensed Consolidated Balance Sheets. The difference between the Company’s estimates and the actual amounts received is recorded in the month that payment is received from the third-party lessee. For the three and six months ended June 30, 2023, royalty income recognized in the reporting period related to performance obligations satisfied in prior reporting periods was $1.4 million. For the three months ended June 30, 2022, royalty income recognized in the reporting period related to

performance obligations satisfied in prior reporting periods was immaterial. For the six months ended June 30, 2022, royalty income of $2.1 million was recognized for a settlement related to the Company’s ownership interest in certain mineral rights.

In accordance with ASC 606-10-50, the Company disaggregates revenue from contracts with customers into major goods and service lines and timing of transfer of goods and services. The Company 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. The Company’s business consists of the Coal Mining, NAMining and Minerals Management segments as well as Unallocated Items. See Note 8 to the Unaudited Condensed Consolidated Financial Statements for further discussion of segment reporting.

The opening and closing balances of the Company’s current and long-term accounts receivable, contract assets and contract liabilities are as follows:

The Company expects to recognize an additional $0.8 million in the remainder of 2023, $1.5 million in 2024, $0.3 million in 2025 and $0.1 million in both 2026 and 2027 related to the contract liability remaining at June 30, 2023. The difference between the opening and closing balances of the Company’s contract balances results from the timing difference between the Company’s performance and the customer’s payment.

The Company has no contract assets recognized from the costs to obtain or fulfill a contract with a customer.

Inventories are summarized as follows:

The timing and amount of any repurchases under the 2021 Stock Repurchase Program are determined at the discretion of the Company's management based on a number of factors, including the availability of capital, other capital allocation alternatives, market conditions for the Company's Class A Common Stock and other legal and contractual restrictions. The 2021 Stock Repurchase Program does not require the Company to acquire any specific number of shares and may be modified, suspended, extended or terminated by the Company without prior notice and may be executed through open market purchases, privately negotiated transactions or otherwise. All or part of the repurchases under the 2021 Stock Repurchase Program may be implemented under a Rule 10b5-1 trading plan, which would allow repurchases under pre-set terms at times when the Company might otherwise be restricted from doing so under applicable securities laws. The Company has not repurchased any shares of common stock under the 2021 Stock Repurchase Program through June 30, 2023.

Bellaire Corporation (“Bellaire”) is a non-operating subsidiary of the Company with legacy liabilities relating to closed mining operations, primarily former Eastern U.S. underground coal mining operations. Prior to 2022, Bellaire contributed $5.0 million to establish a mine water treatment trust (the "Mine Water Treatment Trust") to assure the long-term treatment of post-mining discharge. 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 Company recognized a gain of $0.5 million and $1.0 million during the three and six months ended June 30, 2023, respectively,

and a loss of $1.5 million and $2.1 million during the three and six months ended June 30, 2022, respectively, related to the Mine Water Treatment Trust.

Prior to 2022, the Company 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 Company recognized a loss of $0.1 million and a de minimis gain during the three and six months ended June 30, 2023, respectively, and a loss of $0.4 million and a gain of $0.8 million during the three and six months ended June 30, 2022, respectively, related to the investment in these equity securities.

The change in fair value of equity securities is reported on the line (Gain) loss on equity securities in the Other (income) expense section of the Unaudited Condensed Consolidated Statements of Operations.

There were no transfers into or out of Levels 1, 2 or 3 during the six months ended June 30, 2023 and 2022.

Each of the Company's wholly owned Unconsolidated Subsidiaries, within the Coal Mining and NAMining 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 the Company. Although the Company owns 100% of the equity and manages the daily operations of the Unconsolidated Subsidiaries, the Company has determined that the equity capital provided by the Company 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, the Company is not the primary beneficiary and therefore does 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 $11.1 million and $14.9 million at June 30, 2023 and December 31, 2022, respectively. The Company's maximum risk of loss relating to these entities is limited to its invested capital, which was $4.2 million and $7.1 million at June 30, 2023 and December 31, 2022, respectively. Earnings of unconsolidated operations were $11.1 million and $24.9 million during the three and six months ended June 30, 2023, respectively, and $14.6 million and $29.2 million during the three and six months ended June 30, 2022, respectively.

NACoal 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”), NACoal would be obligated for payment of 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 on or after January 1, 2024 by Coyote Creek’s customers, NACoal 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 NACoal since the inception of these guarantees. The Company believes that the likelihood NACoal would be required to perform under the guarantees is remote, and no amounts related to these guarantees have been recorded.

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 business of the Company. Management believes that it has meritorious defenses and will vigorously defend the Company 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. The Company does 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, the Company discloses 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 the Company’s financial position, results of operations and cash flows of the period in which the ruling occurs, or in future periods.

The Company’s operating segments are: (i) Coal Mining, (ii) NAMining and (iii) Minerals Management. The Company determines its reportable segments by first identifying its 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. The Company’s Chief Operating Decision Maker utilizes operating profit to evaluate segment performance and allocate resources.

The Company has items not directly attributable to a reportable segment that are not included as part of the measurement of segment operating profit, which include primarily administrative costs related to public company reporting requirements at the parent company and the financial results of Mitigation Resources and Bellaire. Mitigation Resources generates and sells stream and wetland mitigation credits (known as mitigation banking) and provides services to those engaged in permittee-responsible stream and wetland mitigation. Bellaire manages the Company’s long-term liabilities related to former Eastern U.S. underground mining activities.

The Company has items not directly attributable to a reportable segment that are not included as part of the measurement of segment operating profit, which primarily includes administrative costs related to public company reporting requirements at the parent company and the financial results of Mitigation Resources and Bellaire Corporation ("Bellaire"). Bellaire manages the Company’s long-term liabilities related to former Eastern U.S. underground mining activities.

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

The Company’s operating segments are further described below:

The Coal Mining segment, operating as North American Coal, LLC ("NACoal"), operates surface coal mines under long-term contracts with power generation companies pursuant to a service-based business model. Coal is surface mined in North Dakota and Mississippi. Each mine is fully integrated with its customer's operations.

During the three and six months ended June 30, 2023, the 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”).

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 in the first quarter of 2023 and final reclamation began on April 1, 2023. Funding for mine reclamation is the responsibility of SWEPCO, and Sabine receives compensation for providing mine reclamation services.

MLMC is the exclusive supplier of lignite to the Red Hills Power Plant in Ackerman, Mississippi. Choctaw Generation Limited Partnership ("CGLP") leases the Red Hills Power Plant from a Southern Company subsidiary pursuant to a leveraged lease arrangement. CGLP's ability to make required payments to the Southern Company subsidiary is dependent on the operational performance of the Red Hills Power Plant. During 2022, Southern Company disclosed that it provided notice to the lessee, CGLP, to terminate the related operating and maintenance agreement effective June 30, 2023. Subsequently, CGLP failed to make the semi-annual lease payment due in December 2022, and as a result, the Southern Company subsidiary was unable to make its corresponding payment to the debtholders. The parties to the lease have entered into a forbearance agreement which suspends the related contractual rights of the parties while they continue restructuring negotiations, which could result in rescission of the termination notice. The ultimate outcome of this matter cannot be determined at this time but could have a material impact on the Company's financial statements if the operating and maintenance agreement is terminated.

At Coteau, Coyote Creek and Falkirk, the Company is 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. The customers are responsible for funding all mine operating costs, including final mine

reclamation, and directly or indirectly provide all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations while providing 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 the Company. See Note 6 to the Unaudited Condensed Consolidated Financial Statements for further discussion of Coyote Creek's guarantees.

Coteau, Coyote Creek, Falkirk and Sabine meet the definition of a variable interest entity ("VIE"). In each case, NACCO is not the primary beneficiary of the VIE as it does not exercise financial control; therefore, NACCO does not consolidate the results of these operations within its financial statements. Instead, these contracts are accounted for as equity method investments. The income before income taxes associated with these VIEs is reported as Earnings of unconsolidated operations on the Unaudited Condensed Consolidated Statements of Operations and the Company’s investment is reported on the line Investments in unconsolidated subsidiaries in the Unaudited Condensed 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 the NACCO consolidated U.S. tax return; therefore, the Income tax (benefit) provision line on the Unaudited Condensed Consolidated Statements of Operations includes income taxes related to these entities. See Note 6 to the Unaudited Condensed Consolidated Financial Statements for further information on the Unconsolidated Subsidiaries.

The Company performs 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.

The MLMC contract is the only operating coal contract in which the Company is responsible for all operating costs, capital requirements and final mine reclamation; therefore, MLMC is consolidated within NACCO’s 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. Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred. As diesel fuel is heavily weighted among the indices used to determine the coal sales price, fluctuations in diesel fuel prices can result in significant fluctuations in earnings at MLMC.

The NAMining segment provides value-added contract mining and other services for producers of industrial minerals. The segment is a platform for the Company’s growth and diversification of mining activities outside of the thermal coal industry. NAMining provides contract mining services for independently owned mines and quarries, creating value for its customers by performing the mining aspects of its customers’ operations. This allows customers to focus on their areas of expertise: materials handling and processing, product sales and distribution. As of June 30, 2023, NAMining operates in Florida, Texas, Arkansas, Indiana, Virginia and Nebraska. Sawtooth Mining, LLC ("Sawtooth") provides comprehensive mining services as the exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

Certain of the entities within the NAMining segment are VIEs and are accounted for under the equity method as Unconsolidated Subsidiaries. See Note 6 to the Unaudited Condensed Consolidated Financial Statements for further discussion.

The Minerals Management segment derives income primarily by leasing its 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 Management segment owns royalty interests, mineral interests, non-participating royalty interests and overriding royalty interests.

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

The Minerals Management segment will benefit from the continued development of its mineral properties without the need for investment of additional capital once mineral and royalty interests have been acquired. The Minerals Management segment does not currently have any material investments under which it would be required to bear the cost of exploration, production or development.

The Company 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 the Company’s legacy reserves were acquired as part of its historical coal mining operations.

In July 2019, the U.S. Environmental Protection Agency (the “EPA”) finalized a rule that repealed the Clean Power Plan (“CPP”) that had been finalized in 2015 and established new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (“ACE”) rule. The ACE rule developed emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generating units (“EGUs”). In response to challenges brought by environmental groups and certain states, the U.S. Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit Court”) vacated the ACE rule, including its repeal of the CPP, in January 2021 and remanded the rule to the EPA for further action. On June 30, 2022, the U.S. Supreme Court issued an opinion reversing the D.C. Circuit Court's decision, and finding that the EPA exceeded its statutory authority when the EPA set emission requirements in the CPP based on generation shifting. On May 11, 2023, the EPA proposed a new rule imposing limits on GHG emissions from existing coal and new natural-gas electric generating units, which could compel such facilities to install additional pollution controls or shut down.

The proposed rule includes guidelines for carbon dioxide ("CO2") emissions from existing EGUs with a proposed compliance date of January 1, 2030. For coal-fired steam EGUs that plan to operate past January 1, 2040, the EPA is proposing a best system of emissions reduction ("BSER") of carbon capture and sequestration/storage ("CCS") with 90 percent capture of CO2 at the stack. For coal-fired steam EGUs that will permanently cease operations after December 31, 2031, but before January 1, 2040, the EPA is proposing a BSER of 40 percent natural gas co-firing on a heat input basis. Coal-fired steam EGUs that will permanently cease operations between December 31, 2031 and January 1, 2035, will be subject to an annual capacity factor limit, and for units that will permanently cease operations before January 1, 2032, the EPA is proposing a BSER of routine

methods of operation and maintenance that maintain current emission rates. Each of the EGUs supplied by the Company would be subject to these proposed requirements.

Additionally, the proposed rule contains other actions, including revised new source performance standards for GHG emissions from new and reconstructed fossil fuel-fired steam EGUs that undertake a large modification. These new rules may raise the cost of fossil fuel generated energy, making coal-fired power plants less competitive, and/or result in early closure which could have an adverse impact on demand for coal and ultimately result in the early closure of the mines servicing these plants, including closure of the Company's coal mines. Any such closure of the Company's mines could have a material adverse effect on the Company’s business, financial condition and results of operations.

The process of burning coal can cause many compounds and impurities in the coal to be released into the air, including sulfur dioxide, nitrogen oxides (“NOx”), mercury, particulates and other matter. The CAA and the corresponding state laws that extensively regulate the emissions of materials into the air affect coal mining operations both directly and indirectly. Direct impacts on coal mining operations occur through CAA permitting requirements and/or emission control requirements relating to air contaminants, especially particulate matter. Indirect impacts on coal mining operations occur through regulation of the air emissions of sulfur dioxide, nitrogen oxides, mercury, particulate matter and other compounds emitted by coal-fired power plants. The EPA has promulgated or proposed regulations that impose tighter emission restrictions in a number of areas, some of which are currently subject to litigation. The general effect of tighter restrictions is to reduce demand for coal. Ongoing reduction in coal’s share of the capacity for power generation could have a material adverse effect on the Company’s business, financial condition and results of operations.

The CAA requires the EPA to review national ambient air quality standards (“NAAQS”) every five years to determine whether revisions to current standards is appropriate. In addition, states are required to submit to the EPA revisions to their state implementation plans ("SIPs") that demonstrate the manner in which the states will attain NAAQS every time a NAAQS is issued or revised by the EPA. The EPA has adopted NAAQS for several pollutants, which continue to be reviewed periodically for revisions. When the EPA adopts new, more stringent NAAQS for a pollutant, some states have to change their existing SIPs. If a state fails to revise its SIP and obtain EPA approval, the EPA may adopt regulations to affect the revision. Coal mining operations and coal-fired power plants that emit particulate matter or other specified material are, therefore, affected by changes in the SIPs. Through this process over the last few years, the EPA has reduced the NAAQS for particulate matter, ozone and nitrogen oxides. The Company's coal mining operations and power generation customers may be directly affected when the revisions to the SIPs are made and incorporate new NAAQS for sulfur dioxide, nitrogen oxides, ozone and particulate matter. In March 2019, the EPA published a final rule that retains the current primary (health-based) NAAQS for sulfur oxides ("SOx") without revision. The current primary standard is set at a level of 75 parts per billion, as the 99th percentile of daily maximum 1-hour sulfur dioxide concentrations, averaged over 3 years. On January 6, 2023, the EPA proposed to lower the level of the particulate matter. If enacted as proposed, this rule would require fossil fuel generating units to install additional emission reducing technologies, which will ultimately increase the cost of fossil fuel generated energy or cause potential EGU retirements.

In 2011, the EPA finalized the Cross-State Air Pollution Rule ("CSAPR") to address interstate transport of pollutants. This affects states in the eastern half of the U.S. and Texas. This rule imposes additional emission restrictions on coal-fired power plants to attain ozone and fine particulate NAAQS. The EPA began implementation of the rule in 2015, when Phase I emission reductions in sulfur dioxide and nitrogen dioxide became effective. In 2019, certain states submitted SIPs to the EPA in response to the 2015 ozone standard reduction. The SIPs were rejected by the EPA on February 13, 2023. On March 15, 2023, the EPA signed the Federal Good Neighbor Plan for the 2015 Ozone NAAQS (“Final FIP”), which provides federal implementation plan ("FIP") requirements for 23 states, including Mississippi where MLMC operates, and requires significant reductions of NOx from power plants and industrial sources in these states. The rule includes emission limits for NOx for fossil fuel-fired EGUs and a “backstop daily emissions rate” for large coal-fired EGUs if they exceed specified limits.

Under the CAA, the EPA also adopts national emission standards for hazardous air pollutants. In December 2011, the EPA adopted a final rule called the Mercury and Air Toxics Standard (“MATS”), which applies to new and existing coal-fired EGUs. This rule requires mercury emission reductions in mercury-containing particulate matter.

In 2020, the EPA issued a final rule reversing a prior finding and determined that it is not “appropriate and necessary” under the CAA to regulate hazardous air pollutant emissions from coal-fired power plants. On February 9, 2022 the EPA proposed a rule to revoke the 2020 finding and to reaffirm the agency’s 2016 finding that it remained “appropriate and necessary” to regulate mercury-containing particulate matter. The EPA finalized the 2022 proposed rule on March 6, 2023, revoking the 2020 finding and concluding that it is appropriate and necessary to regulate mercury-containing particulate matter. In April 2023, the EPA proposed corresponding revisions to the MATS rule. These revisions would remove the mercury emission limit for lignite-fired EGUs and require particulate emission reductions for all coal-fired EGUs. If enacted as proposed, this rule could influence the closure of additional coal-fired EGUs, potentially including all of the EGUs supplied by the Company.

The Company's power generation customers must incur substantial costs to control emissions to meet all of the CAA requirements, including the requirements under MATS and the EPA's regional haze program. These costs raise the price of coal-generated electricity, making coal-fired power less competitive with other sources of electricity, thereby reducing demand for coal. If the Company's customers cannot offset the cost to control certain regulated pollutant emissions by lowering costs or if the Company's customers elect to close coal-fired units, the Company’s business, financial condition and results of operations could be materially adversely affected.

CWA affects coal mining operations by establishing in-stream water quality standards and treatment standards for waste water discharge, including from coal mines. These federal and state requirements could require more costly water treatment and could materially adversely affect the Company’s business, financial condition and results of operations.

The Company believes it has obtained all permits required under the CWA and corresponding state laws and is in compliance with such permits. In many instances, mining operations require securing CWA authorization or a permit from the U.S. Army Corps of Engineers for operations in waters of the United States ("WOTUS.") The Supreme Court of the United States heard the Sackett vs. EPA case in October 2022, which considered whether certain wetlands constitute WOTUS. In the meantime, in January 2023, the EPA published a new rule that redefines WOTUS that relies on the expansive significant nexus test. The new definition expanded the scope of federal jurisdiction over land and water features which could cause some of the Company's operations to incur additional costs to mitigate streams and wetlands. The new WOTUS definition was ultimately stayed in 24 states, including Mississippi, North Dakota and Texas, and on May 25, 2023, the Supreme Court issued its Sackett vs. EPA ruling that defines WOTUS as “a relatively permanent body of water connected to traditional interstate navigable waters” with a “continuous surface connection with that water, making it difficult to determine where the ‘water’ ends and the ‘wetland’ begins.” The Supreme Court decision rejected the “significant nexus” test relied upon by the EPA in its new 2023 WOTUS rule.

As a result, the EPA and the Army Corps of Engineers are authoring a revised definition of WOTUS. This has made securing CWA permits more challenging due to uncertainty.

Bellaire is treating mine water drainage from coal refuse piles associated with former underground coal mines in Ohio and Pennsylvania. Bellaire anticipates that it will need to continue these activities indefinitely. Bellaire was notified by the Pennsylvania Department of Environmental Protection during 2004 that in order to obtain renewal of a permit, Bellaire would be required to establish a mine water treatment trust. See Note 7 and Note 9 to the Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2022 filed on March 15, 2023 for further information on Bellaire.

RCRA affects coal mining operations by establishing requirements for the treatment, storage and disposal of wastes, including hazardous wastes. Coal mine wastes, such as overburden and coal cleaning wastes, currently are exempted from hazardous waste management. In 2020, the EPA finalized changes to the coal combustion residual ("CCR") rule that classified all clay-lined surface impoundments that receive CCR as unlined, which triggered a pond closure date of April 2021 for impoundments that failed the aquifer location restriction. The EPA also established alternative deadlines to cease receipt of waste to include new site-specific alternatives due to lack of capacity with a deadline to initiate closure no later than October 15, 2023 and a new site-specific alternative due to permanent cessation of coal-fired boilers with two deadlines to complete closure: (a) no later than October 17, 2023 for surface impoundments 40 acres or smaller; and (b) October 17, 2028 for surface impoundments larger than 40 acres. These rules may raise the cost for CCR disposal at coal-fired power plants, making them less competitive, and/or result in early closure which could have an adverse impact on demand for coal and ultimately result in the early closure

of the mines servicing these plants, including closure of the Company's mines. Any such closure of the Company's mines could have a material adverse effect on the Company’s business, financial condition and results of operations.

In compliance with the regulations, the owner of the Coal Creek Station power plant, Falkirk’s customer, submitted a Part B application to the EPA in 2020 asserting a unit complied with the CCR rules. In the first quarter of 2023, the EPA proposed to deny the owner’s application. The owner and other parties have submitted additional information and comments supporting the owner’s position. If the EPA ultimately denies the owner’s application, a new liner may need to be installed or new waste management processes and/or units may need to be constructed. Accordingly, it is possible that a denial by the EPA could require a temporary unit shut down. Any temporary unit shut down could result in a temporary suspension of operations at Coal Creek Station. To minimize any impact to operations, Coal Creek Station is moving forward with plans to dry CCR materials produced by the plant, reducing the need to utilize the lined area in question. Falkirk is the sole supplier of lignite coal to Coal Creek Station. Any suspension of operations at Coal Creek Station would eliminate the need for lignite coal during the suspension period. Any such suspension of operations at Coal Creek Station or any of the power plants supplied by the Company's mines could have a material adverse effect on the Company’s business, financial condition and results of operations.

In May 2023, the EPA published proposed regulations that would impose federal regulatory requirements for previously exempt inactive CCR surface impoundments at inactive facilities (legacy CCR surface impoundments). If finalized as proposed, it could increase the regulatory cost of compliance for the Company's customers thereby increasing the cost of power which could materially adversely affect the Company’s business, financial condition and results of operations.

The EPA rule exempts CCRs beneficially used at mine sites and reserves any regulation thereof to the Office of Surface Mining Reclamation and Enforcement ("OSMRE"). The OSMRE suspended all rulemaking actions on CCRs, but could re-initiate them in the future. The outcome of these rulemakings, and any subsequent actions by the EPA and OSMRE, could impact those Company operations that beneficially use CCRs. If the Company were unable to beneficially use CCRs, its revenues for handling CCRs from its customers may decrease and its costs may increase due to the purchase of alternative materials for beneficial uses.

NEPA requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement. There are certain actions associated with surface coal mining that may trigger these types of assessments by federal agencies. When a NEPA action is required, the Company provides the required information to the appropriate federal agency to enable it to complete the required study. Historically, this process has been lengthy and may take several years to complete. In January 2023, the White House Council on Environmental Quality ("CEQ") issued interim guidance that instructs federal agencies to quantify GHG emissions for each alternative and use the social cost of greenhouse gasses to calculate a monetary metric associated with the proposed actions’ climate effects. The NEPA and interim guidance could adversely affect the Company’s ability to secure necessary permits.

On April 21, 2023, President Biden signed a new executive order focused on incorporating environmental justice considerations into federal decision-making. The executive order created a new White House Office of Environmental Justice, and directed all federal agencies to make environmental justice a central part of each agency’s mission by publishing an environmental justice strategic plan for the agency. Additionally, the order requires agencies conducting NEPA reviews to assess direct, indirect and cumulative impacts on environmental justice communities in their analyses, to consider best available science and information on disparate health impacts related to exposure to environmental hazards and provide opportunities for meaningful engagement with environmental justice communities during the environmental review process. It remains to be seen how federal agencies will undertake to comply with these new requirements addressing environmental justice considerations, but the development and application of the new requirements may result in permit uncertainty and delays for activities that require federal approvals.

On June 3, 2023, President Biden signed the Fiscal Responsibility Act of 2023 into law, which included certain provisions collectively known as the Builder Act. These Builder Act includes amendments to NEPA codify past regulatory reforms including narrowing what qualifies as a “major federal action,” limiting the scope of NEPA review to “reasonably foreseeable environmental effects,” narrowing consideration of cumulative effects, directing agencies to only consider technically and economically feasible reasonable alternatives and providing page limits and timelines for environmental impact statements and environmental assessments. It remains to be seen how the changes enacted by Congress will impact site level NEPA analysis.

Refer to the discussion of the Company's Critical Accounting Policies and Estimates as disclosed on pages 52 through 54 in the Company's Annual Report on Form 10-K for the year ended December 31, 2022. The Company's Critical Accounting Policies and Estimates have not materially changed since December 31, 2022.

The results of operations for NACCO were as follows for the three and six months ended June 30:

The components of the change in revenues and operating profit are discussed below in "Segment Results."

and conveyed membership units in Midwest AgEnergy, LLC (“MAG”) with an estimated fair value of $12.8 million. The Company recognized a gain of $16.9 million on the "Other contract termination settlements" line within the accompanying Unaudited Condensed Consolidated Statements of Operations during the second quarter of 2022 as a result of the transactions with GRE.

On December 1, 2022, the Company transferred its ownership interest in MAG to HLCP Ethanol Holdco, LLC. The Company received a payment of $1.2 million in the first six months of 2023 in connection with a post-closing purchase price adjustment, which is included on the line "Other, net" within the accompanying Unaudited Consolidated Statements of Operations. See Note 1 to the Unaudited Condensed Consolidated Financial Statements for further discussion of MAG.

Interest income increased in the second quarter of 2023 and the first six months of 2023 compared with the respective 2022 periods primarily due to a higher average invested cash balance as well as an increase in interest rates.

The Company evaluates and updates its estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of actual earnings compared to projections of earnings between entities that benefit from percentage depletion and those that do not, the effective tax rate may vary quarterly. The benefit of percentage depletion is not directly related to the amount of consolidated pre-tax income recorded in a period. Accordingly, as a result of the significant reduction in 2023 forecasted income before income tax compared with 2022, the proportional effect of the benefit from percentage depletion on the effective income tax rate results in a negative forecasted effective tax rate for 2023. Each quarter, the Company updates its estimate of the annual effective tax rate and makes a cumulative adjustment if the estimated annual tax rate has changed.

The following tables detail NACCO's changes in cash flow for the six months ended June 30:

income partially offset by non-cash adjustments recognized during the first six months of 2022, including $16.9 million related to the termination and release of claims agreement between Falkirk and GRE. An unfavorable change in working capital also contributed to the reduction in net cash provided by operating activities.

The change in net cash used for financing activities was primarily due to fewer repayments during the first six months of 2023 compared with the first six months of 2022.

Financing arrangements are obtained and maintained at the NACCO Natural Resources level. NACCO Natural Resources is the Company's holding Company for NACoal, NAMining, Catapult and Mitigation Resources. NACCO Natural Resources has a secured revolving line of credit of up to $150.0 million (the “Facility”) that expires in November 2025. There were no borrowings outstanding under the Facility at June 30, 2023. At June 30, 2023, the excess availability under the Facility was $117.2 million, which reflects a reduction for outstanding letters of credit of $32.8 million.

NACCO has not guaranteed any borrowings of NACCO Natural Resources. The borrowing agreements at NACCO Natural Resources allow for the payment to NACCO of dividends and advances under certain circumstances. Dividends (to the extent permitted by the Facility) and management fees are the primary sources of cash for NACCO and enable the Company to pay dividends to stockholders and repurchase shares.

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 June 30, 2023, for base rate and LIBOR loans were 1.23% and 2.23%, respectively. The Facility has a commitment fee which is based upon achieving various levels of debt to EBITDA ratios. The commitment fee was 0.34% on the unused commitment at June 30, 2023.

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, in conjunction with maintaining unused availability thresholds of borrowing capacity, as defined in the Facility, of $15.0 million. At June 30, 2023, 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 Resource's 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.

The Company believes funds available from cash on hand, the Facility and operating cash flows will provide sufficient liquidity to meet its operating needs and commitments arising during the next twelve months and until the expiration of the Facility in November 2025.

Expenditures for property, plant and equipment and mineral interests were $14.1 million during the first six months of 2023. Planned expenditures for the remainder of 2023 are expected to be approximately $26 million in the NAMining segment, $20 million in the Minerals Management segment, $7 million in the Coal Mining segment and less than $1.0 million in Unallocated Items.

In the NAMining segment, 2023 capital expenditures are primarily related to the acquisition of equipment to be used at the

Thacker Pass lithium project. Sawtooth is the contract miner for the Thacker Pass lithium project. Under the terms of the contract mining agreement, the customer will reimburse Sawtooth for these capital expenditures over a five-year period from the equipment acquisition date.

Expenditures are expected to be funded from internally generated funds and/or bank borrowings.

NACCO's consolidated capital structure is presented below:

The increase in other net tangible assets at June 30, 2023 compared with December 31, 2022 was mainly the result of an

increase in Trade accounts receivable due to higher sales at NAMining and Mitigation Resources as well as a decrease in Accrued payroll for payments made under the Company's incentive compensation plans during the first six months of 2023. These items were partially offset by a reduction in the Federal income tax receivable during the first six months of 2023.

Since December 31, 2022, there have been no significant changes in the total amount of NACCO's contractual obligations, contingent liabilities or commercial commitments, or the timing of cash flows in accordance with those obligations as reported on page 58 in the Company's Annual Report on Form 10-K for the year ended December 31, 2022. See Note 6 to the Unaudited Condensed Consolidated Financial Statements for a discussion of certain guarantees related to Coyote Creek.

The results of operations for the Coal Mining segment were as follows for the three and six months ended June 30: