# Nacco Industries Inc: Form 10-Q for the period ended Sep 30, 2023

- Company: [Nacco Industries Inc](/companies/nc.md) (CIK 789933)
- Form: 10-Q
- Filed: 2023-11-01
- Accepted by EDGAR: Nov 1, 2023, 16:40 ET
- Period: 2023-09-30
- Accession: 0000789933-23-000054
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/789933/000078993323000054/nacco-20230930.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/789933/000078993323000054/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2023-09-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2023-07-01 to 2023-09-30 | $46.5m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Revenue | 9 months, 2023-01-01 to 2023-09-30 | $158.0m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Cost of revenue | 3 months, 2023-07-01 to 2023-09-30 | $48.7m | us-gaap:CostOfGoodsAndServicesSold |
| Cost of revenue | 9 months, 2023-01-01 to 2023-09-30 | $150.4m | us-gaap:CostOfGoodsAndServicesSold |
| Gross profit | 3 months, 2023-07-01 to 2023-09-30 | −$2.2m | us-gaap:GrossProfit |
| Gross profit | 9 months, 2023-01-01 to 2023-09-30 | $7.6m | us-gaap:GrossProfit |
| Selling, general and administrative | 3 months, 2023-07-01 to 2023-09-30 | $16.1m | us-gaap:SellingGeneralAndAdministrativeExpense |
| Selling, general and administrative | 9 months, 2023-01-01 to 2023-09-30 | $45.7m | us-gaap:SellingGeneralAndAdministrativeExpense |
| Operating income | 3 months, 2023-07-01 to 2023-09-30 | −$6.3m | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2023-01-01 to 2023-09-30 | −$2.7m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2023-07-01 to 2023-09-30 | $632.0k | us-gaap:InterestExpense |
| Interest expense | 9 months, 2023-01-01 to 2023-09-30 | $1.7m | us-gaap:InterestExpense |
| Income tax | 3 months, 2023-07-01 to 2023-09-30 | −$2.0m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 9 months, 2023-01-01 to 2023-09-30 | −$2.6m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2023-07-01 to 2023-09-30 | −$3.8m | us-gaap:NetIncomeLoss |
| Net income | 9 months, 2023-01-01 to 2023-09-30 | $4.4m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2023-07-01 to 2023-09-30 | −$0.51 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 9 months, 2023-01-01 to 2023-09-30 | $0.58 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2023-07-01 to 2023-09-30 | −$0.51 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 9 months, 2023-01-01 to 2023-09-30 | $0.59 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2023-07-01 to 2023-09-30 | 7,517,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 9 months, 2023-01-01 to 2023-09-30 | 7,515,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 9 months, 2023-01-01 to 2023-09-30 | $63.0m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Dividends paid | 9 months, 2023-01-01 to 2023-09-30 | $4.8m | us-gaap:PaymentsOfDividends |
| Share repurchases | 9 months, 2023-01-01 to 2023-09-30 | $824.0k | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2023-09-30 | $128.2m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2023-09-30 | $258.1m | us-gaap:AssetsCurrent |
| Total assets | at 2023-09-30 | $580.9m | us-gaap:Assets |
| Current liabilities | at 2023-09-30 | $60.9m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2023-09-30 | $152.5m | us-gaap:Liabilities |
| Shareholders' equity | at 2023-09-30 | $428.4m | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 84,841 characters.

#### (Amounts in thousands, except as noted and per share data)

Management's Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are based upon management's current expectations and are subject to various uncertainties and changes in circumstances. Important factors that could cause actual results to differ materially from those described in these forward-looking statements are set forth below under the heading “Forward-Looking Statements."

Management's Discussion and Analysis of Financial Condition and Results of Operations include NACCO Industries, Inc.® (“NACCO”) and its wholly owned subsidiaries (collectively, the “Company”). NACCO brings natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through its robust portfolio of NACCO Natural Resources businesses. The Company operates under three business segments: Coal Mining, North American Mining® ("NAMining") and Minerals Management. The Coal Mining segment operates surface coal mines for power generation companies. The NAMining segment is a trusted mining partner for producers of aggregates, activated carbon, lithium and other industrial minerals. The Minerals Management segment, which includes the Catapult Mineral Partners ("Catapult") business, acquires and promotes the development of mineral interests. Mitigation Resources of North America® ("Mitigation Resources") provides stream and wetland mitigation solutions.

The Company has items not directly attributable to a reportable segment that are not included as part of the measurement of segment operating profit. These items primarily include 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:

### Coal Mining Segment

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 nine months ended September 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. During the third quarter of 2023, Sabine and SWEPCO entered into an agreement under which Sabine will provide mine reclamation services through September 30, 2026. On October 1, 2026, SWEPCO will take over and complete the remaining mine reclamation services by acquiring all of the capital stock of Sabine.

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. 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 CGLP to terminate the related operating and maintenance agreement. On July 14, 2023, the Southern Company subsidiary agreed to continue operating the plant for CGLP until the associated power off-take agreement ends in 2032, subject to certain terms and conditions. This restructuring had no material impact on the Company's financial statements.

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. During the first nine months of 2023, MLMC completed mining in the original mine area and moved to a new mine area, which has resulted in increased costs and a reduction in earnings. MLMC does not anticipate opening additional mine areas through the remaining contract term.

### NAMining Segment

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 September 30, 2023, NAMining operates in Florida, Texas, Arkansas, Indiana, Virginia and Nebraska. In addition, 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.

### Minerals Management Segment

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.

- 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, and typically has no environmental liability. 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.

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.

### Government Regulation Update

Other than as described in the following section, there were no significant changes to the Company’s government regulation matters subsequent to December 31, 2022. Information regarding the Company’s government regulation matters is outlined in Part I, Item 1. “Business” in its Annual Report on Form 10-K for the year ended December 31, 2022.

#### Greenhouse Gas (“GHG”) Emissions

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 ("CPP2").

The proposed CPP2 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 CPP2 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.

#### Clean Air Act ("CAA")

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. CSAPR does not affect EGUs in North Dakota. 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.

The EPA’s action to deny the SIPs was challenged in various courts, including the 5th Circuit Court of Appeals (the “Fifth Circuit”). The Fifth Circuit issued a stay of the SIP rejection in Texas, Louisiana, and Mississippi which prevents the Final FIP from going into effect pending the outcome of the litigation challenges to the SIP rejection and Final FIP. On June 5, 2023, the EPA published the Final FIP in the Federal Register. The Final FIP decreases, over time, the ozone-season NOx allowances allocated to generators in the states not affected by the judicial stay beginning in 2024 by assuming that participants in this cap-and-trade program had or would optimize existing NOx controls and later install additional NOx controls. The Company cannot predict the outcome of the legal challenges to the: (i) various state disapprovals; (ii) the Final FIP promulgated on June 5, 2023; and (iii) the interim final rule promulgated on July 31, 2023 that seeks to address the judicial orders.

On July 31, 2023, the EPA promulgated an interim final rule (“interim FIP”) that addresses the various judicial orders where the SIP rejection has been stayed. The interim FIP requires these states to return to the previously approved NOx trading program and emission caps. The interim FIP maintains the state emissions budgets, unit level allowance allocation provisions, and banked allowance holdings reflecting the status quo for the power plants in these states under the Group 2 trading program.

Should the Final FIP be fully implemented in states where a stay has been issued, the rule could influence the closure of some coal-fired EGUs that have not installed selective catalytic reduction technologies, potentially including the EGU supplied by MLMC. Should the interim FIP be implemented, it could result in an increase in the cost to comply with emission limits as the pool of available NOx emission credits will be reduced.

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 EPA's 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 MATS. 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.

#### Clean Water Act ("CWA")

CWA affects coal mining operations by establishing in-stream water quality standards and treatment standards for wastewater 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. Prior to the Supreme Court issuing a decision, in January 2023, the EPA published a new rule that redefines WOTUS that relied on an 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 authored a revised definition of WOTUS, bypassed the rule proposal stage, and promulgated a final rule that removed references to “significant nexus”. The new rule does not go into effect in states where a stay had been issued for the previous rule, including North Dakota, Texas, Louisiana, and Mississippi. In these states, the legal challenge to the rule will resume. In the meantime, securing CWA permits may be more challenging since the agencies in states where a stay has been issued have less guidance to rely on to determine whether certain features are considered WOTUS.

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.

#### Resource Conservation and Recovery Act ("RCRA")

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.

#### National Environmental Policy Act ("NEPA")

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. The Builder Act includes amendments to NEPA which 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.

### CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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.

### CONSOLIDATED FINANCIAL SUMMARY

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

| Revenues: | THREE MONTHS 2023 | 2022 | NINE MONTHS 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Coal Mining | **$18,665** | $22,599 | **$65,661** | $70,163 |
| NAMining | **21,722** | 22,962 | **64,071** | 67,180 |
| Minerals Management | **5,747** | 16,172 | **23,203** | 40,888 |
| Unallocated Items | **966** | 1,092 | **6,785** | 1,901 |
| Eliminations | **(554)** | (1,032) | **(1,683)** | (1,947) |
| Total revenue | **$46,546** | $61,793 | **$158,037** | $178,185 |
| Operating (loss) profit: |  |  |  |  |
| Coal Mining | **$(4,697)** | $6,089 | **$(9,059)** | $34,616 |
| NAMining | **866** | (210) | **3,910** | 2,318 |
| Minerals Management | **3,610** | 10,616 | **16,943** | 35,317 |
| Unallocated Items | **(6,027)** | (6,780) | **(14,445)** | (18,171) |
| Eliminations | **(19)** | 103 | **(52)** | 365 |
| Total operating (loss) profit | **(6,267)** | 9,818 | **(2,703)** | 54,445 |
| Interest expense | **632** | 486 | **1,749** | 1,495 |
| Interest income | **(1,679)** | (352) | **(4,548)** | (692) |
| Closed mine obligations | **394** | 398 | **1,236** | 1,155 |
| Loss (gain) on equity securities | **551** | 316 | **(498)** | 1,676 |
| Income from equity method investee | **—** | (2,156) | **—** | (2,156) |
| Other contract termination settlements | **—** | — | **—** | (16,882) |
| Other, net | **(315)** | (354) | **(2,417)** | (1,648) |
| Other income, net | **(417)** | (1,662) | **(4,478)** | (17,052) |
| (Loss) income before income tax (benefit) provision | **(5,850)** | 11,480 | **1,775** | 71,497 |
| Income tax (benefit) provision | **(2,018)** | 866 | **(2,605)** | 11,121 |
| Net (loss) income | **$(3,832)** | $10,614 | **$4,380** | $60,376 |
| Effective income tax rate | **34.5%** | 7.5% | **(146.8)%** | 15.6% |

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

### Third Quarter of 2023 Compared with Third Quarter of 2022, and First Nine Months of 2023 Compared with First Nine Months of 2022

### Other (income) expense, net

Interest income increased in the third quarter of 2023 and the first nine 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.

Loss (gain) on equity securities represents changes in the market price of invested assets reported at fair value. The change in the third quarter of 2023 and the first nine months of 2023 compared with the respective 2022 periods was due to fluctuations in the market prices of the exchange-traded equity securities. See Note 5 to the Unaudited Condensed Consolidated Financial Statements for further discussion of equity securities.

During the first nine months of 2022, GRE transferred ownership of an office building with an estimated fair value of $4.1 million 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 first nine months of 2022 as a result of the transactions with GRE.

Prior to receiving the membership units from GRE, the Company held a $5.0 million investment in MAG. Subsequent to the receipt of the additional membership units, the Company began to account for the investment under the equity method of accounting. During the third quarter of 2022, the Company recorded $2.2 million, which represented its share of MAG's earnings on the "Income from equity method investee" line within the accompanying Unaudited Condensed Consolidated Statements of Operations.

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 nine months of 2023 in connection with a post-closing purchase price adjustment, which is included on the line "Other, net" within the accompanying Unaudited Condensed Consolidated Statements of Operations. See Note 1 to the Unaudited Condensed Consolidated Financial Statements for further discussion of MAG.

### Income Taxes

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 and may make quarterly comparisons not meaningful. 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.

### LIQUIDITY AND CAPITAL RESOURCES OF NACCO

### Cash Flows

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

| Operating activities: | 2023 | 2022 | Change |
| --- | ---: | ---: | ---: |
| **Net cash provided by operating activities** | **$63,020** | $54,929 | $8,091 |
| **Investing activities:** |  |  |  |
| Expenditures for property, plant and equipment and acquisition of mineral interests | **(37,894)** | (42,004) | 4,110 |
| Other | **339** | 2,766 | (2,427) |
| **Net cash used for investing activities** | **(37,555)** | (39,238) | 1,683 |
| **Cash flow before financing activities** | **$25,465** | $15,691 | $9,774 |

The $8.1 million change in net cash provided by operating activities during the first nine months of 2023 was primarily due to a favorable change in working capital partially offset by a decrease in net income adjusted for non-cash items, primarily the $16.9 million related to the termination and release of claims agreement between Falkirk and GRE. The favorable change in working capital was mainly the result of a reduction in the Federal income tax receivable during the first nine months of 2023 compared with an increase in the first nine months of 2022. In addition, an increase in Accounts Payable during the first nine months of 2023 compared with a decrease in the first nine months of 2022 also contributed to the favorable change in working capital. The increase in 2023 accounts payable is primarily due to $9.9 million related to equipment acquired for the Thacker Pass lithium project.

| Financing activities: | 2023 | 2022 | Change |
| --- | ---: | ---: | ---: |
| Net reductions to long-term debt and revolving credit agreement | **$(2,396)** | $(4,454) | $2,058 |
| Cash dividends paid | **(4,826)** | (4,488) | (338) |
| Purchase of treasury shares | **(824)** | — | (824) |
| **Net cash used for financing activities** | **$(8,046)** | $(8,942) | $896 |

The change in net cash used for financing activities was primarily due to fewer debt repayments during the first nine months of 2023 compared with the first nine months of 2022, partially offset by the purchase of treasury shares during 2023.

### Financing Activities

Financing arrangements are obtained and maintained at the NACCO Natural Resources level. NACCO Natural Resources is the parent 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 September 30, 2023. At September 30, 2023, the excess availability under the Facility was $122.0 million, which reflects a reduction for outstanding letters of credit of $28.0 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 September 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 September 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 September 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

Expenditures for property, plant and equipment and mineral interests were $37.9 million during the first nine months of 2023, primarily for the acquisition of equipment to support the Thacker Pass lithium project. Planned expenditures for the remainder of 2023 are expected to be approximately $5 million in the Coal Mining segment, $4 million in the NAMining segment, $37 million in the Minerals Management segment and less than $1 million in Unallocated Items. In the Minerals Management segment, planned expenditures for the remainder of 2023 are primarily related to the acquisition of mineral and royalty interests in the oil-rich Permian basin. Planned expenditures for 2024 are expected to be approximately $10 million in the Coal Mining segment, $8 million in the NAMining segment, $20 million in the Minerals Management segment and $1 million in Unallocated Items.

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

### Capital Structure

NACCO's consolidated capital structure is presented below:

|  | SEPTEMBER 30 2023 | DECEMBER 31 2022 | Change |
| --- | ---: | ---: | ---: |
| Cash and cash equivalents | **$128,167** | $110,748 | $17,419 |
| Other net tangible assets | **318,154** | 329,045 | (10,891) |
| Intangible assets, net | **25,759** | 28,055 | (2,296) |
| Net assets | **472,080** | 467,848 | 4,232 |
| Total debt | **(22,534)** | (19,668) | (2,866) |
| Bellaire closed mine obligations | **(21,101)** | (21,214) | 113 |
| Total equity | **$428,445** | $426,966 | $1,479 |
| Debt to total capitalization | **5%** | 4% | 1% |

The decrease in other net tangible assets at September 30, 2023 compared with December 31, 2022 was mainly the result of an increase in Accounts payable and a reduction in the Federal income tax receivable. Accounts payable at September 30, 2023 includes $9.9 million related to equipment acquired for the Thacker Pass lithium project. A decrease in Trade accounts receivable due to lower sales at the Coal Mining and Minerals Management segments during the third quarter of 2023 compared with the fourth quarter of 2022 also contributed to the decrease in other net tangible assets. These items were partially offset by an increase in Property, plant and equipment during the first nine months of 2023.

### Contractual Obligations, Contingent Liabilities and Commitments

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.

### SEGMENT RESULTS

### COAL MINING SEGMENT

### FINANCIAL REVIEW

Tons of coal delivered by the Coal Mining segment were as follows for the three and nine months ended September 30:

|  | THREE MONTHS 2023 | 2022 | NINE MONTHS 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Unconsolidated operations | **5,105** | 7,210 | **15,899** | 19,061 |
| Consolidated operations | **628** | 750 | **2,245** | 2,397 |
| Total tons delivered | **5,733** | 7,960 | **18,144** | 21,458 |

27

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

|  | THREE MONTHS 2023 | 2022 | NINE MONTHS 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Revenues | **$18,665** | $22,599 | **$65,661** | $70,163 |
| Cost of sales | **26,819** | 20,933 | **85,966** | 64,421 |
| Gross (loss) profit | **(8,154)** | 1,666 | **(20,305)** | 5,742 |
| Earnings of unconsolidated operations(a) | **11,259** | 13,300 | **33,687** | 40,086 |
| Contract termination settlement | **—** | — | **—** | 14,000 |
| Selling, general and administrative expenses | **7,160** | 8,008 | **20,313** | 22,439 |
| Amortization of intangible assets | **642** | 867 | **2,296** | 2,772 |
| (Gain) loss on sale of assets | **—** | 2 | **(168)** | 1 |
| Operating (loss) profit | **$(4,697)** | $6,089 | **$(9,059)** | $34,616 |

(a) See Note 6 to the Unaudited Condensed Consolidated Financial Statements for a discussion of the Company's unconsolidated subsidiaries, including summarized financial information.

### Third Quarter of 2023 Compared with Third Quarter of 2022

Revenues decreased 17.4% in the third quarter of 2023 compared with the third quarter of 2022 primarily due to a reduction in customer requirements at MLMC.

The following table identifies the components of change in operating (loss) profit for the third quarter of 2023 compared with the third quarter of 2022:

|  | Operating (Loss) Profit |
| --- | ---: |
| 2022 | $6,089 |
| Increase (decrease) from: |  |
| Gross profit, excluding inventory impairment charge | (7,399) |
| Inventory impairment charge | (2,421) |
| Earnings of unconsolidated operations | (2,041) |
| Selling, general and administrative expenses | 848 |
| Amortization of intangibles | 225 |
| Loss on sale of assets | 2 |
| **2023** | **$(4,697)** |

Operating (loss) profit decreased $10.8 million in the third quarter of 2023 compared with the third quarter of 2022 primarily due to decreases in gross profit and in the earnings of unconsolidated operations, partially offset by lower selling, general and administrative expenses.

The decrease in gross profit was primarily the result of an increase in the cost per ton delivered at MLMC. The increase in cost per ton delivered at MLMC is due to costs associated with establishing operations in a new mine area and a reduction in the number of tons severed. The reduction in severed tons was due to adverse mining conditions caused by the amount of rain during the third quarter of 2023, as well as operational inefficiencies related to final mining activities at the existing mine area. Fewer tons severed caused a decrease in tons held in inventory since more tons were delivered than produced during the third quarter of 2023. This resulted in an increase in the cost per ton and a $2.4 million inventory impairment charge to write down coal inventory to its net realizable value.

The decrease in the earnings of unconsolidated operations was primarily due to a reduction in customer requirements at Coteau.

The decrease in selling, general and administrative expenses was primarily due to lower employee-related costs.

### First Nine Months of 2023 Compared with First Nine Months of 2022

Revenues decreased 6.4% in the first nine months of 2023 compared with the first nine months of 2022 primarily due to a reduction in customer requirements at MLMC.

The following table identifies the components of change in operating (loss) profit for the first nine months of 2023 compared with the first nine months of 2022:

|  | Operating (Loss) Profit |
| --- | ---: |
| 2022 | $34,616 |
| Increase (decrease) from: |  |
| Gross profit, excluding inventory impairment charges | (19,406) |
| Contract termination settlement in 2022 | (14,000) |
| Inventory impairment charges | (6,641) |
| Earnings of unconsolidated operations | (6,399) |
| Selling, general and administrative expenses | 2,126 |
| Amortization of intangibles | 476 |
| Gain on sale of assets | 169 |
| **2023** | **$(9,059)** |

Operating (loss) profit decreased $43.7 million in the first nine months of 2023 compared with the first nine months of 2022 due to a decrease in gross profit, the non-recurrence of $14.0 million recognized in the first nine months of 2022 related to the contract termination settlement with GRE and a decline in the earnings of unconsolidated operations. These decreases were partially offset by lower selling, general and administrative expenses.

The decrease in gross profit was primarily due to an increase in the cost per ton delivered at MLMC. The increase in cost per ton delivered at MLMC is due to costs associated with establishing operations in a new mine area and a reduction in the number of tons severed. The reduction in severed tons was due to adverse mining conditions caused by the amount of rain during the first nine months of 2023, as well as operational inefficiencies related to final mining activities at the existing mine area. Fewer tons severed caused a decrease in tons held in inventory since more tons were delivered than produced during the first nine months of 2023. This resulted in an increase in the cost per ton and $6.6 million of inventory impairment charges to write down coal inventory to its net realizable value.

The decrease in the earnings of unconsolidated operations was primarily due to a reduction in the per ton management fee at Falkirk, effective May 2022 through May 2024, to support the transition of the Coal Creek Station Power Plant to Rainbow Energy. A reduction in customer requirements at Coteau and Falkirk also contributed to the decrease in earnings. These decreases were partly offset by improved results at Coyote Creek.

The decrease in selling, general and administrative expenses was primarily due to lower employee-related costs.

### NORTH AMERICAN MINING ("NAMining") SEGMENT

### FINANCIAL REVIEW

Tons delivered by the NAMining segment were as follows for the three and nine months ended September 30:

|  | THREE MONTHS 2023 | 2022 | NINE MONTHS 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Total tons delivered | **15,410** | 13,421 | **44,178** | 40,756 |

29

The results of operations for the NAMining segment were as follows for the three and nine months ended September 30:

|  | THREE MONTHS 2023 | 2022 | NINE MONTHS 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Total revenues | **$21,722** | $22,962 | **$64,071** | $67,180 |
| Reimbursable costs | **13,339** | 15,259 | **38,088** | 41,337 |
| Revenues excluding reimbursable costs | **$8,383** | $7,703 | **$25,983** | $25,843 |
| Total revenues | **$21,722** | $22,962 | **$64,071** | $67,180 |
| Cost of sales | **20,286** | 21,853 | **58,411** | 62,086 |
| Gross profit | **1,436** | 1,109 | **5,660** | 5,094 |
| Earnings of unconsolidated operations(a) | **1,495** | 1,288 | **3,975** | 3,716 |
| Selling, general and administrative expenses | **2,065** | 2,607 | **5,725** | 6,417 |
| Loss on sale of assets | **—** | — | **—** | 75 |
| Operating profit (loss) | **$866** | $(210) | **$3,910** | $2,318 |

(a) See Note 6 to the Unaudited Condensed Consolidated Financial Statements for a discussion of the Company's unconsolidated subsidiaries, including summarized financial information.

### Third Quarter of 2023 Compared with Third Quarter of 2022

Total revenues decreased 5.4% in the third quarter of 2023 compared with the third quarter of 2022 primarily due to a decrease in reimbursable costs, which have an offsetting amount in cost of sales and have no impact on operating profit, and a decrease in mine reclamation revenue at Caddo Creek. These decreases were partially offset by an increase in customer requirements and tons delivered at the consolidated quarries.

The following table identifies the components of change in operating profit (loss) for the third quarter of 2023 compared with the third quarter of 2022:

|  | Operating Profit (Loss) |
| --- | ---: |
| 2022 | $(210) |
| Increase (decrease) from: |  |
| Voluntary retirement program charge | 769 |
| Selling, general and administrative expenses | 307 |
| Earnings of unconsolidated operations | 207 |
| Gross profit | (207) |
| **2023** | **$866** |

Operating profit increased $1.1 million in the third quarter of 2023 compared with the third quarter of 2022 primarily due to the absence of a voluntary retirement program charge and a decrease in selling, general and administrative expenses.

During the third quarter of 2022, the Company implemented a voluntary retirement program for employees who met certain age

and service requirements to reduce overall headcount. As a result of this program, the third quarter 2022 operating loss includes

a charge of $0.8 million related to one-time termination benefits.

The decrease in selling, general and administrative expenses was mainly due to lower employee-related costs.

### First Nine Months of 2023 Compared with First Nine Months of 2022

Total revenues decreased 4.6% in the first nine months of 2023 compared with the first nine months of 2022 primarily due to a reduction in revenue from reclamation activities at Caddo Creek. The Marshall Mine, where Caddo Creek had been performing mine reclamation work, was acquired by the Company in the first quarter of 2023. A decrease in reimbursable costs, which have an offsetting amount in cost of sales and have no impact on operating profit, also contributed to the decrease in total revenues. These decreases were partially offset by an increase in customer requirements and tons delivered at the consolidated quarries.

The following table identifies the components of change in operating profit for the first nine months of 2023 compared with the first nine months of 2022:

|  | Operating Profit |
| --- | ---: |
| 2022 | $2,318 |
| Increase (decrease) from: |  |
| Voluntary retirement program charge | 769 |
| Selling, general and administrative expenses | 457 |
| Earnings of unconsolidated operations | 259 |
| Loss on sale of assets | 75 |
| Gross profit | 32 |
| **2023** | **$3,910** |

Operating profit increased $1.6 million in the first nine months of 2023 compared with the first nine months of 2022 primarily due to the absence of a voluntary retirement program charge and a decrease in selling, general and administrative expenses.

During the third quarter of 2022, the Company implemented a voluntary retirement program for employees who met certain age

and service requirements to reduce overall headcount. As a result of this program, the first nine months of 2022 operating profit includes a charge of $0.8 million related to one-time termination benefits.

The decrease in selling, general and administrative expenses was mainly due to lower employee-related costs.

In addition, the change in gross profit was due to higher earnings at the consolidated quarries as well as an increase in dragline part sales, largely offset by the absence of earnings associated with Caddo Creek reclamation activities.

### MINERALS MANAGEMENT SEGMENT

### FINANCIAL REVIEW

The results of operations for the Minerals Management segment were as follows for the three and nine months ended September 30:

|  | THREE MONTHS 2023 | 2022 | NINE MONTHS 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Revenues | **$5,747** | $16,172 | **$23,203** | $40,888 |
| Cost of sales | **1,064** | 1,006 | **3,026** | 2,487 |
| Gross profit | **4,683** | 15,166 | **20,177** | 38,401 |
| Selling, general and administrative expenses | **986** | 611 | **3,147** | 1,672 |
| Loss (gain) on sale of assets | **87** | — | **87** | (2,527) |
| Asset impairment charges | **—** | 3,939 | **—** | 3,939 |
| Operating profit | **$3,610** | $10,616 | **$16,943** | $35,317 |

During the third quarter of 2023 and the first nine months of 2023, the oil and natural gas industry experienced a decline in commodity prices compared with the respective 2022 periods. Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. The table below demonstrates such volatility with the average price as reported by the United States Energy Information Administration for the three and nine months ended September 30:

|  | THREE MONTHS 2023 | 2022 | NINE MONTHS 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| West Texas Intermediate Average Crude Oil Price | **$82.30** | $93.18 | **$77.38** | $98.79 |
| Henry Hub Average Natural Gas Price | **$2.59** | $7.99 | **$2.47** | $6.71 |

Revenues and operating profit decreased significantly in the third quarter of 2023 and the first nine months of 2023 compared with the respective 2022 periods, primarily due to substantially lower natural gas and oil prices, as well as lower settlement income. The first nine months of 2023 and the first nine months of 2022 included settlement income of $1.4 million and $2.1 million, respectively. Settlement income relates to the Company’s ownership interest in certain mineral rights.

In addition, operating profit in the first nine months of 2023 decreased due to a $2.4 million gain on the sale of land related to legacy operations recognized during the second quarter of 2022.

An increase in selling, general and administrative expenses, mainly due to higher employee-related costs, also contributed to the decrease in operating profit.

The Company regularly performs reviews of potential future development projects and identified certain legacy coal assets

where future development is unlikely. The long-lived assets, which included land, prepaid royalties and capitalized leasehold

costs, were written off in the third quarter of 2022 and resulted in non-cash asset impairment charges of $3.9 million.

### UNALLOCATED ITEMS AND ELIMINATIONS

### FINANCIAL REVIEW

Unallocated Items and Eliminations were as follows for the three and nine months ended September 30:

|  | THREE MONTHS 2023 | 2022 | NINE MONTHS 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Operating loss | **$(6,046)** | $(6,677) | **$(14,497)** | $(17,806) |

The operating loss in the third quarter of 2023 and the first nine months of 2023 decreased compared with the respective 2022 periods due to lower employee-related costs. The first nine months of 2023 also included higher earnings at Mitigation Resources.

### NACCO Industries, Inc. Outlook

### Coal Mining Outlook

The Company expects fourth-quarter 2023 Coal Mining operating results and Segment Adjusted EBITDA to improve significantly compared with the 2023 third quarter but decline substantially from the 2022 fourth quarter.

The improvement in fourth-quarter 2023 over third-quarter 2023 results is primarily due to anticipated lower production costs from completion of the move to a new mine area at MLMC partially offset by anticipated higher Coal Mining operating expenses due to higher professional fees and outside services. While production costs at MLMC are anticipated to decline significantly from recent levels, production costs are expected to remain above historical levels through 2024 when a pit extension in the new mine area is complete. All production costs are capitalized into inventory at this mine. Beginning in the 2023 fourth quarter, MLMC expects to increase the number of tons severed, which is anticipated to lead to an increase in coal inventory levels. Higher inventory levels will allow costs to be spread over more tons, which is expected to result in a lower cost per ton sold and improved profitability beginning with the fourth quarter and going forward.

The fourth-quarter 2023 results at MLMC are expected to be below fourth-quarter 2022 despite the improvement in results over the previous 2023 quarters. An anticipated increase in operating expenses is also expected to contribute to the lower fourth-quarter 2023 results.

MLMC does not anticipate opening additional mine areas through the remaining contract term. While increased depreciation from capital expenditures related to the new mine area will affect future results, the Company anticipates MLMC should contribute favorably to Segment Adjusted EBITDA in future years.

Capital expenditures are expected to be approximately $5 million in the fourth quarter of 2023, $10 million for the 2023 full year, and $10 million in 2024.

### Coal Mining Outlook - 2024

In 2024, the Company expects coal deliveries to increase moderately from 2023 levels. Higher Coteau and Falkirk deliveries are expected to be partly offset by the unfavorable effect of the Pirkey Plant retirement and resulting March 31, 2023 cessation of coal deliveries from the Company's Sabine Mine.

Strong operating profit and significantly higher Segment Adjusted EBITDA are expected in 2024 compared with 2023. These increases are primarily the result of significant improvements in results at MLMC due to the anticipated reduction in cost per ton sold and an increase in earnings of unconsolidated operations. Improvements are expected to be higher in the second half of 2024 as comparisons are made to much lower second-half 2023 results.

The anticipated higher earnings at the unconsolidated coal mining operations are expected to be driven primarily by increased customer requirements at Coteau and Falkirk, as well as a higher per ton management fee at Falkirk beginning in June 2024 when temporary price concessions end.

The Company's contract structure at each of its coal mining operations eliminates exposure to spot coal market price fluctuations. However, fluctuations in natural gas prices, weather and the availability of renewable power generation, particularly wind, can contribute to changes in power plant dispatch and customer demand for coal. Changes to customer power plant dispatch would affect the Company’s outlook for the remainder of 2023 and 2024, as well as over the longer term.

### NAMining Outlook

NAMining expects fourth-quarter 2023 tons delivered to decrease modestly from 2022, while full-year 2023 tons delivered are expected to increase year-over-year as a result of the increased deliveries in the first nine months of 2023.

Operating profit and Segment Adjusted EBITDA are anticipated to increase significantly in both the 2023 fourth quarter and full year over the respective prior year periods. These increases are primarily due to anticipated earnings improvement under existing contracts, including Sawtooth, partially offset by the completion of services at Caddo Creek.

In 2024, NAMining expects full-year operating profit and Segment Adjusted EBITDA to increase significantly over 2023 due to improved earnings under certain existing contracts, including Sawtooth, and an anticipated reduction in operating expenses. Any new contracts should be accretive to NAMining's future results.

Sawtooth has an exclusive agreement to provide comprehensive mining services for the Thacker Pass lithium project in northern Nevada, owned by Lithium Nevada Corp., a subsidiary of Lithium Americas Corp. (TSX: LAC) (NYSE: LAC). Lithium Americas controls the lithium reserves at Thacker Pass. In March 2023, Lithium Americas commenced construction at Thacker Pass. With construction beginning, Sawtooth started acquiring mining equipment in the 2023 second quarter. Sawtooth has acquired $23.1 million of equipment to-date. While Lithium Americas will reimburse Sawtooth for these capital expenditures over a five-year period, Sawtooth will recognize the associated revenue over the estimated useful life of the asset. In addition, during the construction period, Sawtooth will be reimbursed for all costs of construction and will recognize a contractually agreed construction fee. The Company expects to continue to recognize moderate income prior to the expected commencement of Phase 1 lithium production in the second half of 2026.

NAMining expects full-year 2023 capital expenditures to be approximately $34 million, with approximately $4 million expended in the fourth quarter. In 2024, capital expenditures are expected to be approximately $8 million, primarily for the acquisition of dragline parts and other equipment.

### Minerals Management Outlook

The Minerals Management segment derives income from royalty-based leases under which lessees make payments to the Company based on their sale of natural gas, oil, natural gas liquids and coal, extracted primarily by third parties. Changing prices of natural gas and oil could have a significant impact on Minerals Management’s operating profit.

In the 2023 fourth quarter and full year, operating profit and Segment Adjusted EBITDA are expected to continue to decrease significantly compared with the respective prior year periods. These decreases are primarily driven by current market expectations for natural gas and oil prices.

In 2024, operating profit and Segment Adjusted EBITDA are expected to increase moderately compared with 2023 primarily driven by current market expectations for natural gas and oil prices and limited forecasted development of additional new wells by third-party lessees. Lower operating expenses are also expected to contribute to the profit growth.

The Company's forecast is based on current market assumptions for natural gas and oil market prices, as well as currently owned reserves. Commodity prices are inherently volatile. Economic uncertainty continues to drive commodity price volatility and any change in natural gas and oil prices from current expectations will result in adjustments to the Company's outlook. The Company is closely monitoring the Israel/Gaza conflict and its potential impact on OPEC countries and international oil and gas production and demand. The actions of OPEC, inventory levels of natural gas and oil and the uncertainty associated with demand, as well as other factors, have the potential to impact future oil and gas prices. Current merger and acquisition activity within the oil and gas industry is also a focus as the Company works to understand its potential impact on development plans by third-party lessees.

As an owner of royalty and mineral interests, the Company’s access to information concerning activity and operations with respect to its interests is limited. The Company's expectations are based on the best information currently available and could vary positively or negatively as a result of adjustments made by operators, additional leasing and development and/or changes to commodity prices. Development of additional wells on existing interests in excess of current expectations, or acquisitions of additional interests, could be accretive to future results.

In 2023, Minerals Management expects capital expenditures of approximately $39 million, which includes the anticipated acquisition of approximately $37 million of mineral and royalty interests expected to close during the fourth quarter that will provide additional diversification into the oil-rich Permian basin. The anticipated fourth quarter acquisition exceeds the previously announced capital expenditure projection as management believes it offers an attractive investment profile and aligns with the Company's strategy to establish a diversified portfolio of mineral and royalty interests. In 2024, Minerals Management is targeting additional investments of up to $20 million. Future investments are expected to be accretive, but each investment's contribution to near-term earnings is dependent on the details of that investment, including the size and type of interests acquired and the stage and timing of mineral development.

### Mitigation Resources

Mitigation Resources continues to build on the substantial foundation it established over the past several years. Mitigation Resources currently has nine mitigation banks and four permittee-responsible mitigation projects located in Tennessee, Mississippi, Alabama and Texas. In addition, Mitigation Resources is providing ecological restoration services for abandoned surface mines, as well as pursuing additional environmental restoration projects. It was named a designated provider of abandoned mine land restoration by the State of Texas. Mitigation Resources plans to continue to expand its business during the remainder of 2023 and in 2024, and expects to achieve near break-even earnings in 2024 and sustainable profitability in future years.

### Consolidated Outlook

Overall, the Company expects that fourth-quarter 2023 improvements will produce operating profit and net income compared with consolidated third-quarter losses. However, fourth-quarter and full-year 2023 consolidated operating results and Adjusted EBITDA are expected to be down significantly from the respective prior-year periods due to substantial decreases at the Coal Mining and Minerals Management segments. These reductions are expected to be partially offset by favorable changes in income taxes leading to modest net income for the 2023 full year.

In 2024, the Company expects a significant increase in consolidated net income and EBITDA over 2023. These improvements are primarily due to increased profitability at the Coal Mining segment from improved results at MLMC, Falkirk and Coteau. Growth at NAMining and Mitigation Resources is also expected to contribute to the higher 2024 net income. The Company expects an effective income tax rate between 10% and 13% in 2024. Additional contracts for NAMining or Mitigation Resources or the acquisition of additional mineral interests at Minerals Management, including the $37 million investment expected to close in the 2023 fourth quarter, could be accretive to the current forecast.

Consolidated capital expenditures are expected to total approximately $84 million in 2023, which includes approximately $39 million at Minerals Management and $24 million related to the Thacker Pass lithium project. As a result of the forecasted capital expenditures and anticipated substantial decrease in net income, cash flow before financing activities in 2023 is expected to be a moderate use of cash. In 2024, the Company expects capital expenditures of approximately $39 million, including up to $20 million of investments at Minerals Management. Cash flow before financing activities in 2024 is expected to be positive but not to the level generated in 2022.

### Long-term Growth and Diversification

Management continues to view the long-term business outlook for NACCO positively. The Company is pursuing growth and diversification by strategically leveraging its core mining and natural resources management skills to build a strong portfolio of affiliated businesses. Management continues to be optimistic about the long-term outlook. In the Minerals Management segment, as well as in the Company's Mitigation Resources business, opportunities for growth remain strong. Acquisitions of additional mineral interests, an improvement in the outlook for the Company's largest Coal Mining segment customers, and securing contracts for Mitigation Resources and new NAMining projects could be accretive to the Company's outlook.

The Minerals Management segment continues to pursue acquisitions of mineral and royalty interests in the United States. Catapult, the Company’s business unit focused on managing and expanding the Company’s portfolio of oil and gas mineral and royalty interests, has developed a strong network to source and secure new acquisitions. The goal is to construct a high-quality diversified portfolio of oil and gas mineral and royalty interests in the United States that delivers near-term cash flow yields and long-term projected growth. The Company believes this business will provide unlevered after-tax returns on invested capital in the mid-teens as this business model matures. This business model can deliver higher average operating margins over the life of a reserve than traditional oil and gas companies that bear the cost of exploration, production and/or development as these costs are borne entirely by third-party exploration and development companies that lease the minerals.

The Company remains committed to expanding the NAMining business while working to improve profitability. NAMining intends to be a substantial contributor to operating profit over time, specifically in its Sawtooth subsidiary when production commences at Thacker Pass, which is projected to occur in 2026. Once production commences, Sawtooth will receive a management fee per metric ton of lithium delivered. At maturity, this contract is expected to deliver fee income similar to a mid-sized management fee coal mine.

The pace of achieving substantially improved results at NAMining will depend on the execution and successful implementation of profit improvement initiatives in the aggregates operations, and the mix and scale of new projects. A number of initiatives are already delivering improved financial results.

Mitigation Resources continues to expand its business, which creates and sells stream and wetland mitigation credits, provides services to those engaged in permittee-responsible mitigation and provides other environmental restoration services. This business offers an opportunity for growth and diversification in an industry where the Company has substantial knowledge and expertise and a strong reputation. Mitigation Resources is making strong progress toward its goal of becoming a top ten provider of stream and wetland mitigation services in the southeastern United States. The Company believes that Mitigation Resources can provide solid rates of return on capital employed as this business matures.

The Company also continues to pursue activities which can strengthen the resiliency of its existing coal mining operations. The Company remains focused on managing coal production costs and maximizing efficiencies and operating capacity at mine locations to help customers with management fee contracts be more competitive. These activities benefit both customers and the Company's Coal Mining segment, as fuel cost is a significant driver for power plant dispatch. Increased power plant dispatch results in increased demand for coal by the Coal Mining segment's customers. Fluctuating natural gas prices, weather and availability of renewable energy sources, such as wind and solar, could affect the amount of electricity dispatched from coal-fired power plants. While the Company realizes the coal mining industry faces political and regulatory challenges and demand for coal is projected to decline over the longer-term, the Company believes coal should be an essential part of the energy mix in the United States for the foreseeable future.

The Company continues to look for ways to create additional value by utilizing its core mining competencies which include reclamation and permitting. The Company is working to utilize these skills through development of utility-scale solar projects on reclaimed mining properties. Reclaimed mining properties offer large tracts of land that could be well-suited for solar and other energy-related projects. These projects could be developed by the Company itself or through joint ventures that include partners with expertise in energy development projects.

The Company is committed to maintaining a conservative capital structure as it continues to grow and diversify, while avoiding unnecessary risk. Strategic diversification will generate cash that can be re-invested to strengthen and expand the businesses. The Company also continues to maintain the highest levels of customer service and operational excellence with an unwavering focus on safety and environmental stewardship.

### FORWARD-LOOKING STATEMENTS

The statements contained in this Form 10-Q that are not historical facts are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are made subject to certain risks and uncertainties, which could cause actual results to differ materially from those presented. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. The Company undertakes no obligation to publicly revise these forward-looking statements to reflect events or circumstances that arise after the date hereof. Among the factors that could cause plans, actions and results to differ materially from current expectations are, without limitation: (1) changes to or termination of customer or other third-party contracts, or a customer or other third party default under a contract, (2) any customer's premature facility closure, (3) regulatory actions, including the United States Environmental Protection Agency's 2023 proposed rules relating to mercury and greenhouse gas emissions for coal-fired power plants, changes in mining permit requirements or delays in obtaining mining permits that could affect deliveries to customers, (4) a significant reduction in purchases by the Company's customers, including as a result of changes in coal consumption patterns of U.S. electric power generators, or changes in the power industry that would affect demand for the Company's coal and other mineral reserves, (5) changes in the prices of hydrocarbons, particularly diesel fuel, natural gas, natural gas liquids and oil, (6) failure or delays by the Company's lessees in achieving expected production of natural gas and other hydrocarbons; the availability and cost of transportation and processing services in the areas where the Company's oil and gas reserves are located; federal and state legislative and regulatory initiatives relating to hydraulic fracturing; and the ability of lessees to obtain capital or financing needed for well-development operations and leasing and development of oil and gas reserves on federal lands, (7) failure to obtain adequate insurance coverages at reasonable rates, (8) supply chain disruptions, including price increases and shortages of parts and materials, (9) changes in tax laws or regulatory requirements, including the elimination of, or reduction in, the percentage depletion tax deduction, changes in mining or power plant emission regulations and health, safety or environmental legislation, (10) the ability of the Company to access credit in the current economic environment, or obtain financing at reasonable rates, or at all, and to maintain surety bonds for mine reclamation as a result of current market sentiment for fossil fuels, (11) impairment charges, (12) the effects of investors’ and other stakeholders’ increasing attention to environmental, social and governance matters, (13) changes in costs related to geological and geotechnical conditions, repairs and maintenance, new equipment and replacement parts, fuel or other similar items, (14) weather conditions, extended power plant outages, liquidity events or other events that would change the level of customers' coal or aggregates requirements, (15) weather or equipment problems that could affect deliveries to customers, (16) changes in the costs to reclaim mining areas, (17) costs to pursue and develop new mining, mitigation, oil and gas and solar development opportunities and other value-added service opportunities, (18) delays or reductions in coal or aggregates deliveries, (19) the ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives, (20) disruptions from natural or human causes, including severe weather, accidents, fires, earthquakes and terrorist acts, any of which could result in suspension of operations or harm to people or the environment, and (21) the ability to attract, retain, and replace workforce and administrative employees.

## Market risk

As filed, 154 characters.

As a “smaller reporting company” as defined by Rule 12b-2 of the Securities Exchange Act of 1934, the Company is not required to provide this information.

## Controls and procedures

As filed, 836 characters.

**Evaluation of disclosure controls and procedures:** An evaluation was carried out under the supervision and with the participation of the Company's management, including the principal executive officer and the principal financial officer, of the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, these officers have concluded that the Company's disclosure controls and procedures are effective.

**Changes in internal control over financial reporting:** During the third quarter of 2023, there have been no changes in the Company's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

### PART II

### OTHER INFORMATION

## Risk factors

As filed, 3,450 characters.

During the nine months ended September 30, 2023, there have been no material changes to the risk factors previously disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2022, except as follows:

**The coal mining industry is subject to ongoing complex governmental regulations and legislation that could adversely impact the Company’s long-term mining contracts and the Company’s results of operations, liquidity, financial condition and cash flow.**

The United States Environmental Protection Agency (the “EPA”) has a comprehensive regulatory program to manage the disposal of coal combustion residuals (“CCR”) from coal-fired power plants as non-hazardous material under the Resource Conservation and Recovery Act (“RCRA”). Individual states administer some or all of the RCRA provisions. The North Dakota Department of Environmental Quality approved Falkirk’s customer's plan for an alternate disposal liner to store coal ash at the Coal Creek Station power plant. In the first quarter of 2023, the EPA proposed to deny the application. If denied, a new liner or new waste management unit(s) may need to be installed, which could result in the 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.

The EPA also has a comprehensive regulatory program to manage airborne emissions from coal-fired power plants. During the first nine months of 2023, the EPA proposed updated rules related to mercury and greenhouse gas emissions from coal-fired power plants. The first update was to the Mercury Air Toxics Standard, or MATS. In this update, the EPA proposed to eliminate a mercury emission standard for lignite-fired power plants that currently permits higher mercury emissions by lignite plants than other coal plants. In the event this rule is adopted as proposed, and not successfully legally challenged, it could result in the closure of many lignite-fired power plants, potentially including all of those supplied by the Company. The second update was the EPA’s proposed new rule for greenhouse gas emissions from coal-fired power plants. In this proposed new rule, the EPA requires that power plant owners that intend to operate the plants beyond 2031 utilize controls, including reduced levels of power generation, co-firing coal and natural gas and installing carbon capture and sequestration to reduce greenhouse gas emissions. Each of these controls may impact the plant owners’ profitability and could result in the closure of coal-fired power plants, potentially including all of those supplied by the Company. The closure of any of the power plants supplied by the Company could have a material adverse effect on the Company’s business, financial condition and results of operation.

See the Government Regulation Update on page 19 of this Quarterly Report on Form 10-Q for further information.

Filed Nov 1, 2023.
Source: SEC EDGAR, the filing index for accession 0000789933-23-000054. Last ingested by Listed: Nov 4, 2026, 18:21 ET. No prices; not investment advice.