UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)
☑	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended	December 31, ~~2024~~2025


☐						TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 1-9172

NACCO INDUSTRIES, INC.

(Exact name of registrant as specified in its charter)

Delaware

34-1505819

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

22901 Millcreek Blvd,

Suite 600

Cleveland,

Ohio

44122

(Address of principal executive offices)

(Zip Code)

Registrant's telephone number, including area code: (440) 229-5151

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

Title of each class

Trading Symbol

Name of each exchange on which registered

Class A Common Stock, $1 par value per share

New York Stock Exchange

Class A Common Stock, $1 par value per share

NYSE Texas

Securities registered pursuant to Section 12(g) of the Act: Class B Common Stock, $1 par value per share. Class B Common Stock is not publicly listed for trade on any exchange or market system; however, Class B Common Stock is convertible into Class A Common Stock on a share-for-share basis.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No £

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

Yes þ No £

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

Large accelerated filer

☐

Accelerated filer

☑

Non-accelerated filer

☐

Smaller reporting company

☑

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes ☐ No ☑

Aggregate market value of Class A Common Stock and Class B Common Stock held by non-affiliates as of June 30, ~~2024~~2025 (the last business day of the registrant's most recently completed second fiscal quarter): $~~117~~118,~~744~~562,~~151~~800

Number of shares of Class A Common Stock outstanding at February 2827, ~~2025~~2026: 5,~~866~~971,~~937~~635

Number of shares of Class B Common Stock outstanding at February 2827, ~~2025~~2026: 1,~~565~~562,~~359~~953

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company's Proxy Statement for its ~~2025~~2026 annual meeting of stockholders are incorporated herein by reference in Part III of this Form 10-K.

NACCO INDUSTRIES, INC.

TABLE OF CONTENTS

			PAGE
PART I.
	Item 1.	BUSINESS	1
	Item 1A.	RISK FACTORS	1815
	Item 1B.	UNRESOLVED STAFF COMMENTS	2723
	Item 1C.	CYBERSECURITY	2824
	Item 2.	PROPERTIES	2925
	Item 3.	LEGAL PROCEEDINGS	4844
	Item 4.	MINE SAFETY DISCLOSURES	4844
PART II.
	Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	4945
	Item 6.	[RESERVED]	4945
	Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	5046
	Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	6459
	Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	6459
	Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	6459
	Item 9A.	CONTROLS AND PROCEDURES	6459
	Item 9B.	OTHER INFORMATION	6459
	Item 9C.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	6459
PART III.
	Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	6560
	Item 11.	EXECUTIVE COMPENSATION	6560
	Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	6560
	Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	6560
	Item 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	6560
PART IV.
	Item 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	6661
	Item 16.	FORM 10-K SUMMARY	7166
SIGNATURES			7267
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			F-1

Table of Contents

PART I

Item 1. BUSINESS

General

NACCO Industries, Inc.® (NACCO) and its wholly owned subsidiary, NACCO Natural Resources Corporation® (NACCO Natural Resources, and with NACCO collectively, the Company, we, our or us), bring natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through our robust portfolio of businesses. We operate under three reportable business segments: Utility Coal Mining, ~~North~~Contract ~~American~~ Mining® ~~(NAMining)~~ and Minerals ~~Management~~and Royalties. The Utility Coal Mining segment, ~~operates~~operated by North American Coal®, manages surface coal mines that are exclusive, long-term fuel providers for power generation companies. The ~~NAMining~~Contract Mining segment, isoperated aby ~~trusted~~North ~~mining~~American ~~partner~~Mining®, ~~for~~is ~~producers~~a leading provider of ~~aggregates,~~a ~~activated~~broad ~~carbon,~~range ~~lithium~~of ~~and~~specialized, ~~other~~long-term ~~industrial~~contract ~~minerals~~mining services. The Minerals ~~Management~~and Royalties 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~~royalty ~~mitigation~~interests ~~solutions as well as comprehensive reclamation~~ and ~~restoration~~other ~~construction~~related ~~services~~investments. ~~In addition, ReGen Resources is pursuing opportunities to develop new power generation resources.~~

WeIn ~~have~~addition ~~items~~to ~~not~~the ~~directly~~reportable ~~attributable~~segments todiscussed aabove, ~~reportable~~we ~~segment~~also operate other businesses that are not ~~included~~currently ~~in the~~ reported ~~financial~~as ~~results~~separate ~~of the operating segment~~segments. These ~~items~~businesses ~~primarily~~complement ~~include~~our ~~administrative~~existing ~~costs~~operations ~~related~~and tosupport ~~public~~our ~~company~~long-term ~~reporting~~growth ~~requirements,~~strategic ~~including~~objectives. ~~management~~Mitigation ~~and~~Resources ~~board~~of ~~compensation,~~North ~~and~~America® ~~the~~(Mitigation ~~financial~~Resources) ~~results~~provides ofnatural ~~Bellaire~~resource ~~Corporation~~restoration ~~(Bellaire),~~and ~~Mitigation~~reclamation ~~Resources,~~services ~~ReGen~~that ~~Resources~~include stream and ~~other~~wetland ~~developing~~mitigation ~~businesses~~solutions. ~~Bellaire~~ReGen ~~manages~~Resources ~~our~~is ~~long-term~~pursuing ~~liabilities~~opportunities ~~related~~ to ~~former~~develop ~~Eastern~~new ~~U.S.~~power ~~underground~~generation ~~mining activities~~resources.

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

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

NACCO was incorporated as a Delaware corporation in 1986 in connection with the formation of a holding company structure for a predecessor corporation organized in 1913.

Business Strategy

NACCO’s ~~portfolio~~is ofa ~~businesses~~growing ~~operate~~diversified ~~under~~natural ~~the~~resource ~~umbrella~~company, ofstrategically ~~NACCO~~positioned ~~Natural~~to ~~Resources.~~deliver ~~Management~~stable ~~continues~~financial toreturns ~~view~~over ~~our~~the long~~-term~~ ~~business outlook positively~~term. Our businesses operate exclusively in the U.S. and provide critical inputs for electricity generation, construction and development, and the production of industrial minerals and ~~chemicals~~products. Increasing demand for electricity, on-shoring and current federal policies are creating favorable macroeconomic trends within these industries. ~~Management~~We iscontinue ~~confident~~to incapitalize on these tailwinds, pursuing longer-term growth opportunities. Through our ~~trajectory~~proven operational expertise, disciplined capital allocation, and ~~business~~an ~~prospects~~entrepreneurial asyet ~~well~~patient asapproach ~~longer-term~~to growth, we have methodically built unique capabilities and clear competitive advantages that enable us to capture a wide range of attractive growth opportunities. Our platform is supported by multiple vectors for value creation, and we are steadfastly committed to delivering compounding returns and expanding investor value over the long term.

~~While~~Our webusiness ~~realize~~model ~~the~~is ~~coal~~purposely ~~mining~~built ~~industry~~for ~~continues~~durability toand ~~face~~resilience. ~~challenges~~Our foundation rests on a stable base of long-term coal-mining contracts which, wewhen ~~believe~~combined ~~the~~with ~~current~~income ~~political~~generated ~~environment~~by ~~may~~our ~~change~~mineral ~~the~~and ~~sentiment~~royalty ~~surrounding~~assets, ~~fossil~~provide ~~fuel~~dependable ~~industry-related~~recurring ~~regulations~~cash flows. ~~These~~As ~~developments~~new long-term contracts and investments are ~~expected~~added toeach ~~further~~year ~~support~~in ~~coal~~our other businesses, these multi-year agreements create a “layering” effect as antheir ~~essential~~contributions ~~part~~compound. ofEach ~~the~~year’s ~~energy~~new ~~mix~~contracts inand ~~the~~investments ~~United~~add ~~States~~to ~~for~~those ~~the~~of ~~foreseeable~~prior ~~future.~~years, delivering increasingly predictable cash flows and annuity-like returns.

~~NAMining~~Our iscompetitive ~~our~~advantages ~~primary~~include ~~platform~~decades ~~for~~of ~~growth around mining activities. With a focus on~~ operational ~~excellence,~~expertise ~~scalability~~in ~~and~~complex ~~driving~~mining ~~profitable growth~~operations, ~~NAMining~~long-standing ~~expects~~customer torelationships ~~improve~~with ~~operating~~industry ~~margins~~leaders, asexclusive ~~well~~dealership asrights ~~achieve~~for ~~additional~~MTECK ~~growth~~draglines ~~through~~in ~~its~~48 ~~ongoing business development activities~~U.S. ~~New~~states ~~contracts~~ and ~~contract~~a ~~extensions~~proven ~~are~~ability ~~central~~ to ~~the~~structure ~~business'~~long ~~organic~~term ~~growth~~contracts ~~strategy.~~that ~~The~~align ~~goal~~incentives isand todeliver ~~continue~~value ~~NAMining's~~to ~~ongoing~~both ~~expansion~~NACCO asand aour ~~leading provider of contract mining services for~~ customers. ~~who~~We ~~produce~~also maintain a ~~wide~~conservative ~~variety~~capital ofstructure ~~minerals~~that ~~and~~provides ~~materials,~~flexibility ~~and we expect NAMining~~ to bepursue aopportunities ~~substantial~~while ~~contributor~~maintaining tofinancial ~~operating profit over time~~stability.

~~The~~Our ~~Minerals~~Utility ~~Management~~Coal Mining segment, ~~through~~anchored by our ~~Catapult business, has constructed a high~~long-~~quality,~~term ~~diversified~~mining ~~portfolio~~contracts ~~of oil~~ and ~~gas~~fee-based ~~mineral~~models ~~and royalty interests in the United States~~ that isprovide ~~expected~~predictable ~~to deliver near-term~~ cash ~~flow~~flows ~~yields~~ and ~~long-term~~eliminate ~~growth.~~exposure ~~As an owner of mineral and royalty interests, we are entitled~~ to acommodity ~~portion of the revenues received from the production of oil~~prices, natural gas and associated natural gas liquids, typically net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. The current portfolio provides a ~~strong~~solid foundation of ~~well-positioned~~our ~~assets that are expected to continue to deliver solid financial results~~business. We ~~This~~believe ~~business model can deliver higher average operating margins over~~ the ~~life~~increasing ofdemand afor ~~reserve~~24/7 ~~than traditional oil and gas companies that bear the full cost of exploration~~electricity, ~~production~~driven ~~and/or~~by ~~development.~~data ~~We intend to continue these activities~~centers, ~~while at the same time evaluating investments in non~~on-~~operated~~shoring ~~working~~of ~~interests~~manufacturing ~~that we believe can reliably increase cash flow~~ and ~~enhance~~general ~~overall~~economic ~~returns. As a non-operator~~growth, wecombined ~~seek to diversify our investment and operational risk through participation in oil and gas wells~~ with ~~multiple operators across multiple basins. While~~ the ~~timing~~current ofpolitical ~~returns could vary~~environment, weis ~~maintain~~fundamentally achanging ~~long-term perspective and believes~~ the ~~Minerals~~sentiment ~~Management~~surrounding ~~segment~~fossil ~~will provide unlevered after~~fuel-~~tax~~based ~~returns~~power ongeneration ~~invested~~and ~~capital in the mid-teens as the business matures.~~

Mitigation Resources, which provides stream and wetland mitigation solutions as well as comprehensive reclamation and restoration construction services, continues to build on the substantial foundation it has established over the past several years. Our Mitigation Resources business offers an opportunity for growth and diversification in an industry where we have a strong

Table of Contents

~~reputation~~provides asstability ~~well~~the asUtility ~~substantial~~Coal ~~knowledge~~Mining ~~and expertise~~business. InThese ~~addition,~~developments ~~Mitigation~~are ~~Resources~~improving isindustry-related ~~providing~~regulations ~~ecological~~and ~~restoration~~reinforcing ~~services~~coal's ~~for~~role ~~abandoned~~as ~~surface~~an ~~mines~~essential ~~and~~part ~~was~~of ~~named~~the areliable, ~~designated~~baseload ~~provider~~energy ofmix ~~abandoned~~in ~~mine~~the ~~land~~United ~~restoration~~States byfor the ~~State~~foreseeable ~~of Texas~~future. ~~Mitigation~~We ~~Resources~~remain isfocused ~~working~~on tomanaging ~~develop~~coal aproduction ~~protected~~costs ~~habitat~~and ~~for~~maximizing ~~toads~~efficiencies inand ~~Texas,~~operating ascapacity ~~well~~at asmine ~~pursuing~~locations ~~additional~~to ~~environmental~~help ~~restoration~~customers ~~projects.~~with Wemanagement ~~believe~~fee ~~that~~contracts ~~Mitigation~~be ~~Resources~~more ~~can~~competitive. ~~provide~~These ~~solid~~activities ~~rates~~benefit ofboth ~~return~~customers onand ~~capital~~our ~~employed~~Utility asCoal ~~this~~Mining ~~business~~segment, ~~matures.~~as Asfuel ofcost ~~December~~is ~~31,~~a ~~2024,~~significant wedriver ~~have~~for 11power ~~mitigation~~plant ~~banks~~dispatch. ~~and~~Increased ~~other~~power ~~mitigation~~plant ~~projects~~dispatch ~~located~~results in ~~Alabama,~~increased ~~Florida,~~demand ~~Georgia,~~for ~~Mississippi,~~coal ~~Pennsylvania,~~by ~~Tennessee~~the ~~and~~Utility ~~Texas.~~Coal Mining segment's customers.

WeThe ~~believe~~Contract Mining segment represents our ~~businesses~~mining growth platform. We have ~~competitive~~long-term ~~advantages~~relationships ~~that~~and ~~provide~~contracts ~~value~~with toseveral ~~customers~~of the top ten U.S. aggregates producers. Our expanding pipeline of potential mining contracts and ~~continuing~~continued toengagement ~~invest~~with incustomers ~~our~~position ~~businesses~~this ~~can~~segment ~~create~~as ~~long-term~~a ~~value~~key pillar for ~~stockholders~~future growth. WeThrough ~~have~~ongoing ~~strategically~~geographic ~~leveraged~~and ~~our~~mineral ~~core~~expansion, ~~mining~~we are building a growing portfolio of long-term contracts. New contracts and ~~natural~~contract ~~resources~~extensions ~~management~~are ~~skills~~central to ~~build~~the abusiness' ~~robust~~organic ~~portfolio~~growth ofstrategy, ~~affiliated~~with ~~businesses~~each new contract expected to contribute operating profit and ~~opportunities~~EBITDA ~~for~~through ~~additional~~multi-year ~~growth~~terms ~~remain~~that ~~strong~~can span a decade or more. ~~Acquisitions~~The ofgoal ~~additional~~is ~~mineral~~to ~~interests~~continue ~~and~~Contract ~~improvements~~Mining's inongoing ~~the~~expansion ~~outlook~~as a leading provider of contract mining services for ~~Coal~~a ~~Mining~~variety ~~segment~~of customers,. asThe ~~well~~segment’s asstrong ~~new~~momentum ~~contracts~~is atevident ~~Mitigation~~through ~~Resources~~recent ~~and~~contract ~~NAMining~~wins, ~~and~~including ~~development~~a multi-year dragline services contract for a U.S. Army Corps of ~~other~~Engineers ~~business~~construction ~~opportunities~~project ~~should~~in bePalm ~~accretive~~Beach County, Florida, which showcases our ability to expand into large scale infrastructure projects while highlighting the competitive advantage of our ~~longer-term~~new ~~outlook~~electric drive MTECK draglines.

~~NACCO~~The ~~also~~Minerals ~~continues~~and toRoyalties ~~pursue~~segment ~~activities~~is ~~which~~another ~~can~~solid ~~strengthen~~foundation ~~the resiliency~~ of our ~~existing~~business. ~~coal~~It ~~mining~~has ~~operations.~~constructed Wea ~~remain~~high-quality, ~~focused~~diversified onportfolio ~~managing~~of ~~coal~~oil ~~production~~and ~~costs~~gas mineral and ~~maximizing~~royalty ~~efficiencies~~interests with recurring cash flows. As an owner of mineral and ~~operating~~royalty ~~capacity~~interests, atwe ~~mine~~are ~~locations~~entitled to ~~help~~a ~~customers~~portion ~~with~~of ~~management~~the ~~fee~~revenues ~~contracts~~received befrom ~~more~~the ~~competitive.~~sale ~~These~~of ~~activities~~oil, ~~benefit~~natural ~~both~~gas ~~customers~~ and ~~our~~associated ~~Coal~~natural ~~Mining~~gas ~~segment,~~liquids. asThe ~~fuel~~current ~~cost~~portfolio of well-positioned assets is aexpected ~~significant~~to ~~driver~~continue ~~for~~to ~~power~~deliver ~~plant~~solid ~~dispatch~~financial results. ~~Increased~~We ~~power~~seek ~~plant~~to ~~dispatch~~diversify ~~results~~our investment and operational risk through participation in ~~increased~~oil ~~demand~~and ~~for~~gas ~~coal~~wells bywith ~~the~~multiple ~~Coal~~operators ~~Mining~~across ~~segment~~multiple basins. Catapult's ~~customers.~~portfolio ~~Fluctuating~~of ~~natural~~oil and gas ~~prices~~mineral and royalty interests provides steady, ~~weather~~recurring ~~and~~cash ~~availability~~flows, ofwith ~~renewable~~strategic ~~energy~~positions ~~sources~~in premier basins, ~~such~~primarily asin ~~wind~~the ~~and~~Permian ~~solar~~Basin, ~~could~~the ~~affect~~Haynesville Shale basin and the ~~amount~~Appalachian ofbasin. ~~electricity~~We ~~dispatched~~also ~~from~~maintain ~~coal~~equity investments in a private company that holds operated and non-~~fired~~operated ~~power~~working ~~plants~~interests in oil and natural gas assets in the Kansas and the Oklahoma portion of the Hugoton basin.

WeMitigation ~~continue~~Resources toprovides ~~look~~natural ~~for~~resource ~~ways~~restoration toand ~~create~~reclamation ~~additional~~services ~~value~~that byinclude ~~utilizing~~stream ~~our~~and ~~core~~wetland ~~mining~~mitigation ~~competencies,~~solutions. ~~which~~Mitigation ~~include~~Resources ~~reclamation~~is ~~and~~successfully ~~permitting.~~leveraging ~~NACCO~~its ~~established~~strong ~~ReGen~~reputation ~~Resources~~and toclear ~~utilize~~competitive ~~these~~strengths ~~skills~~ to ~~address~~expand ~~the~~into ~~rapidly~~additional ~~increasing~~mitigation, ~~demand~~restoration ~~for~~and ~~additional~~reclamation ~~power~~markets. ~~generation~~Mitigation ~~sources~~Resources inis ~~the~~expected ~~United~~to ~~States~~deliver ~~through~~increasing ~~development~~profitability ofover ~~energy-related~~time ~~projects~~from ~~that~~the ~~utilize~~sale ~~multiple~~of ~~generation~~mitigation ~~technologies,~~credits ~~such~~and as ~~solar~~reclamation ~~combined~~and ~~with~~restoration ~~gas-fired~~services ~~generation,~~expand. ~~primarily~~We onexpect ~~reclaimed~~the ~~mining~~reclamation ~~properties.~~and ~~These~~restoration ~~projects~~business ~~could~~to begenerate ~~developed~~increasing byprofits ~~ReGen~~as ~~Resources~~this ~~directly~~part orof ~~through~~the ~~joint~~business ~~ventures~~grows. ~~that~~The ~~include~~timing ~~partners~~of ~~with~~profits ~~expertise~~from inthe ~~energy~~mitigation ~~development~~solutions ~~projects~~part ~~and~~of ~~their~~the ~~financing.~~business ~~Current~~is ~~opportunities~~inherently inmore ~~development~~variable ~~include~~as ~~solar~~project ~~arrays,~~credits ~~solar-gas~~only ~~hybrid~~become ~~projects~~available ~~and~~for ~~carbon~~sale ~~capture~~once oncertain ~~reclaimed~~permit ~~mine~~criteria ~~land~~are inmet. ~~Mississippi~~During ~~and Texas~~2025, asMitigation ~~well~~Resources asoperated ~~early-stage~~in ~~review~~Alabama, ofFlorida, ~~projects~~Georgia, inKentucky, ~~other~~Mississippi, ~~states~~Pennsylvania, Tennessee, Texas and Virginia.

NACCO isestablished ~~committed~~ReGen Resources to ~~maintaining~~address athe ~~conservative~~rapidly ~~capital~~increasing ~~structure~~demand asfor itpower ~~continues~~generation toin ~~grow~~the ~~and~~United ~~diversify~~States. Current projects in development include solar arrays, ~~while~~solar-gas ~~avoiding~~hybrid ~~unnecessary~~projects, ~~risk.~~thermal Wegeneration ~~believe~~and ~~strategic~~carbon ~~diversification~~capture ~~will~~primarily ~~generate~~on ~~cash~~reclaimed ~~that~~mining ~~can~~properties bein ~~re-invested~~Louisiana, toMississippi, ~~strengthen~~Ohio, Pennsylvania and ~~expand~~Texas. ~~our~~ReGen ~~businesses~~develops energy infrastructure projects directly as well as through joint ventures. WeOur ~~also~~investments ~~continue~~in solar projects are dependent, in part, on federal tax incentives to ~~maintain~~preserve ~~the~~economic ~~highest~~value. ~~levels~~We ofbelieve ~~customer~~all ~~service~~current ~~and~~solar ~~operational~~projects ~~excellence~~have ~~with~~been ansafe ~~unwavering~~harbored ~~focus~~in onorder ~~safety~~to ~~and~~preserve ~~environmental~~tax ~~stewardship~~credit eligibility.

We believe our businesses have competitive advantages that provide value to customers, and the continuing investment in our businesses can create long-term value for stockholders. We have strategically leveraged our core mining and natural resource management skills to build a robust portfolio of affiliated businesses, and opportunities for additional growth remain strong. New contracts, acquisitions of additional mineral interests, improvements in industry-related regulations, and the development of other business opportunities should be accretive to our longer-term outlook.

NACCO is committed to maintaining a conservative capital structure as it continues to grow and diversify, while avoiding unnecessary risk. We believe strategic diversification will generate cash that can be re-invested at attractive returns to strengthen and grow our businesses. We also continue to maintain the highest levels of customer service and operational excellence.

Business Developments

~~Coal~~During 2025, the Contract Mining ~~Segment~~segment executed a multi-year dragline services contract for a U.S. Army Corps of Engineers construction project in Palm Beach County, Florida. This project should be accretive to earnings beginning in the second quarter of 2026.

During 2023, Mississippi Lignite Mining Company (MLMC) received notice from its customer related to a boiler issue at the Red Hills Power Plant that began on December 15, 2023. We assessed MLMC's long-lived assets for impairment and recorded a $65.9 million impairment charge in 2023. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on the long-lived asset impairment charge. While this issue has been resolved, it resulted in a reduction in customer demand which had a significant impact on our 2024 results of operations. We recognized income of $13.6 million in 2024 related to business interruption insurance recoveries that partially offset losses as a result of the boiler outage.

The Sabine Mining Company (Sabine) operates the Sabine Mine in Texas. All production from Sabine was delivered to

Southwestern Electric Power Company's (SWEPCO) Henry W. Pirkey Plant (the Pirkey Plant). SWEPCO is an American

Electric Power (AEP) company. As a result of the early retirement of the Pirkey Plant, Sabine ceased deliveries and commenced final reclamation on April 1, 2023. Funding for mine reclamation is the responsibility of SWEPCO, and Sabine receives compensation for providing mine reclamation services. Sabine will provide mine reclamation services through September 30, 2026. As of October 1, 2026, SWEPCO has an obligation to acquire all of the capital stock of Sabine and complete the remaining mine reclamation.

NAMining Segment

Sawtooth Mining, LLC (Sawtooth) will be the exclusive provider of comprehensive mining services for the Thacker Pass lithium project in Humboldt County, Nevada. Thacker Pass is owned by a joint venture between Lithium Americas Corp. (TSX: LAC) (NYSE: LAC) and General Motors Holdings LLC. Thacker Pass commenced construction in 2023 and is targeting initial production in 2027. Sawtooth will be reimbursed for costs of mining, capital expenditures and mine closure and will recognize a contractually agreed upon production fee once the mine is operating. In addition to providing comprehensive mining services,

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~~Sawtooth~~During is2025 ~~currently~~and ~~assisting~~2024, ~~with~~the ~~certain~~Contract ~~construction~~Mining ~~services~~segment amended and ~~will~~extended ~~transport~~existing ~~clay~~limestone ~~tailings~~contracts ~~once~~with ~~lithium~~multiple ~~production~~customers ~~commences~~and expanded the scope of work with several other customers. See Item 2. Properties on page 38 in this Form 10-K for a list of the Contract Mining segment's locations and customers.

During ~~2024~~2025 and ~~2023~~2024, ~~NAMining~~the ~~amended~~Minerals and ~~extended~~Royalties ~~existing~~segment ~~limestone~~invested ~~contracts~~$15.0 ~~with~~million ~~two~~and ~~customers~~$16.6 ~~and~~million, ~~expanded~~respectively, ~~the~~in ~~scope~~Eiger ofResources, ~~work~~which ~~with~~holds ~~several~~operated ~~other~~and ~~customers.~~non-operated ~~New~~working ~~contracts~~interests ~~signed~~in oil and natural gas assets in ~~2024~~the ~~are~~Kansas ~~expected~~and tothe beOklahoma ~~accretive~~portion of the Hugoton basin. See Note 1 to ~~earnings~~the ~~starting~~Consolidated Financial Statements in ~~2026~~this Form 10-K for further information on Eiger Resources.

During 2025, the Minerals ~~Management~~and ~~Segment~~Royalties segment completed $4.6 million in acquisitions of mineral interests, primarily within the Midland Basin. The acquisition includes a mix of producing wells, as well as additional upside opportunities through future development with existing operators in the area.

During ~~2024~~2025, we terminated NACCO's Combined Defined Benefit Plan (Combined Plan) and ~~2023,~~settled ~~Minerals~~all ~~Management~~future ~~invested~~obligations by transferring the remaining benefit obligations to a ~~total~~third-party ofinsurance ~~$19~~company.1 ~~million~~Although the plan was over funded, ~~including~~we recognized a $~~15.~~7 .8 million innon-cash Pension settlement charge. See Note 1 and Note 14 to the ~~fourth~~Consolidated ~~quarter~~Financial ofStatements in this Form 10-K for further information on the Combined Plan.

2024, in Eiger, LLC (Eiger), which holds non-operated working interests in oil and natural gas assets in the Kansas and the Oklahoma portion of the Hugoton basin.

During 2023, Minerals Management acquired $36.7 million of mineral and royalty interests in the Texas portion of the Permian Basin.

Other Items

In December 2023, we entered into a power purchase agreement with the Tennessee Valley Authority (TVA) for the energy generated from a proposed 67.5 MW solar photovoltaic electric generation facility to be developed on reclaimed land at our Red Hills Mine. The development of this project is subject to the favorable completion of an Environmental Assessment under the National Environmental Policy Act (NEPA) and approval of an interconnection agreement with TVA. In addition, we entered into an engineering, procurement and construction agreement related to the interconnection of the project during 2025. The estimated commercial operation date for this generation facility is late 2027.

Operations

Utility Coal Mining Segment

The Utility Coal Mining segment operates surface coal mines under exclusive, long-term contracts ~~with power generation companies pursuant~~ to asupply ~~service-based~~100% ~~business~~of ~~model.~~the ~~Coal~~fuel isrequirements ~~surface~~for ~~mined~~adjacent inpower ~~North~~plants ~~Dakota~~ and ~~Mississippi~~a synfuels plant. Each mine is fully integrated with ~~our~~the ~~customer's~~operation ~~operations.~~of these facilities.

As of December 31, ~~2024~~2025, the Utility Coal Mining segment's operating coal mines were: The Coteau Properties Company (Coteau), Coyote Creek Mining Company, LLC (Coyote Creek), The Falkirk Mining Company (Falkirk) and ~~MLMC.~~Mississippi ~~Each~~Lignite ofMining ~~these~~Company ~~mines~~(MLMC). ~~supply~~Coteau, ~~lignite~~Falkirk ~~coal for power generation~~ and ~~delivers~~Coyote ~~our~~Creek ~~coal~~are ~~production~~in toNorth anDakota ~~adjacent~~and ~~power~~MLMC ~~plant~~is orin ~~synfuels~~Mississippi. ~~plant~~Each ~~under~~of athese ~~long-term~~mines ~~supply~~produce ~~contract~~lignite coal. While MLMC’s coal supply contract contains a take or pay provision, the contract contains a force majeure provision that allows for the temporary suspension of the take or pay provision during the duration of certain specified events beyond the control of either party; all other coal supply contracts are requirements contracts. Certain coal supply contracts can be terminated early, which would result in a reduction to future earnings.

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

AtIn ~~Coteau~~December 2023, ~~Coyote~~MLMC ~~Creek~~received ~~and~~notice ~~Falkirk~~from its customer related to a boiler issue at the Red Hills Power Plant. While this issue has been resolved, weit ~~are~~resulted ~~paid~~in a ~~management~~reduction ~~fee~~in ~~per~~customer ~~ton~~demand which had a significant impact on our results of ~~coal~~operations orduring ~~heating~~2024. ~~unit~~We ~~(MMBtu)~~recognized ~~delivered~~income of $13.6 million ~~Each~~in ~~contract~~2024 ~~specifies~~related to business interruption insurance recoveries that partially offset losses as a result of the ~~indices~~boiler ~~and~~outage. ~~mechanics~~In byFebruary ~~which~~2026, ~~fees~~MLMC ~~change~~received ~~over~~notice ~~time~~from its customer that the Red Hills Power Plant experienced an unplanned outage, ~~generally~~which inis ~~line~~expected ~~with~~to ~~broad~~lead to reduced demand and an anticipated operating loss for MLMC during 2026.

~~measures~~The ofSabine ~~U.S.~~Mining ~~inflation.~~Company ~~Our~~(Sabine) ~~customers~~operates ~~are~~the ~~responsible~~Sabine ~~for~~Mine ~~funding~~in ~~all~~Texas. ~~mine~~All ~~operating~~production ~~costs,~~from ~~including~~Sabine ~~final~~was ~~mine~~delivered ~~reclamation,~~to ~~and~~Southwestern ~~directly~~Electric orPower ~~indirectly~~Company's ~~providing~~(SWEPCO) ~~all~~Henry ofW. ~~the~~Pirkey ~~capital~~Plant ~~required~~(the toPirkey ~~build~~Plant). ~~and~~SWEPCO ~~operate~~is ~~the~~an ~~mine.~~American ~~This~~Electric ~~contract~~Power ~~structure~~(AEP) ~~eliminates~~company. ~~exposure~~As toa ~~spot~~result ~~coal~~of ~~market~~the ~~price~~early ~~fluctuations~~retirement ~~while~~of ~~providing~~the ~~income~~Pirkey ~~and~~Plant, ~~cash~~Sabine ~~flow~~ceased ~~with~~deliveries ~~minimal~~and ~~capital~~commenced ~~investment.~~final ~~Other~~reclamation ~~than~~on atApril ~~Coyote Creek~~1, ~~debt~~2023. ~~financing~~Funding ~~provided~~for bymine orreclamation ~~supported~~is by the ~~customers~~responsibility isof ~~without~~SWEPCO, ~~recourse~~and toSabine ~~us.~~receives ~~See~~compensation ~~Note~~for 16providing tomine ~~the~~reclamation ~~Consolidated~~services. ~~Financial~~Sabine ~~Statements~~will inprovide ~~this~~mine ~~Form~~reclamation ~~10-K~~services ~~for~~through ~~further~~September ~~discussion~~30, ~~of Coyote Creek's guarantees.~~

Coteau, Coyote Creek, Falkirk and Sabine each meet the definition of a variable interest entity (VIE). In each case, NACCO

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is2026. ~~not~~As ~~the primary beneficiary~~ of ~~the~~October ~~VIE as it does not exercise financial control; therefore~~1, ~~we do not consolidate the results of these operations within our financial statements. Instead~~2026, ~~these~~SWEPCO ~~contracts are accounted for as equity method investments. The income before income taxes associated with these VIEs~~ is ~~reported~~obligated asto ~~Earnings~~acquire all of ~~unconsolidated operations on~~ the ~~Consolidated~~capital ~~Statements~~stock of ~~Operations~~Sabine and ~~our~~complete ~~investment is reported on~~ the ~~line~~remaining ~~Investments~~mine ~~in unconsolidated subsidiaries in the Consolidated Balance Sheets~~reclamation. The mines that meet the definition of a VIE are referred to collectively as the Unconsolidated Subsidiaries. For tax purposes, the Unconsolidated Subsidiaries are included within our consolidated U.S. tax return; therefore, the Income tax benefit line on the Consolidated Statements of Operations includes income taxes related to these entities. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further information on the Unconsolidated Subsidiaries.

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

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

We perform contemporaneous reclamation activities at each mine in the normal course of operations. Under all of the Unconsolidated Subsidiaries’ contracts, our 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.

See Item 2. Properties on page 2925 in this Form 10-K for discussion of ~~our~~the Utility Coal Mining segment's mineral resources and mineral reserves.

~~NAMining~~Contract Mining Segment

The ~~NAMining~~Contract Mining segment provides value-added contract mining and other services for producers of industrial minerals and products. The segment is a platform for our growth and diversification of mining activities outside of the thermal coal industry. ~~NAMining~~Contract Mining provides contract mining services for independently owned mines and quarries, creating value for our customers by performing the mining aspects of our customers’ operations. This allows customers to focus on their areas of expertise: materials handling and processing, product sales and distribution. As of December 31, ~~2024~~2025, ~~NAMining~~the Contract Mining segment operates at quarries in Florida, ~~Texas,~~ Arkansas, ~~Virginia~~ and Nebraska and is expected to begin operations at a quarry in Arizona during the first half of 2026. Beginning in 2026, the Contract Mining segment will also provide dragline services as part of a U.S. Army Corps of Engineers construction project in Palm Beach County, Florida.

In addition, ~~Sawtooth~~Contract ~~will~~Mining's ~~supply~~subsidiary, ~~all~~Sawtooth ofMining (Sawtooth), is the ~~lithium-bearing~~exclusive ~~ore~~provider ~~requirements~~of comprehensive mining services for the Thacker Pass lithium project in Humboldt County, ~~which~~Nevada. Thacker Pass is ~~currently~~owned by a joint venture between Lithium Americas Corp. (TSX:LAC) (NYSE: LAC) and General Motors Holdings LLC. The U.S. Department of Energy holds warrants to purchase five percent non-voting, non-transferable equity in ~~the~~this ~~development~~joint ~~stage~~venture. ~~with~~Thacker ~~construction~~Pass ~~activities~~is ~~underway~~targeting initial lithium production in late 2027. ~~Sawtooth~~The ~~will~~contract berequires ~~reimbursed~~reimbursement for costs of mining, capital expenditures and mine closure. ~~and~~Sawtooth will recognize a contractually agreed upon production fee once the mine is operating. In addition to providing comprehensive mining services, Sawtooth is currently assisting with certain construction services and will transport clay tailings once lithium production commences.

~~Minerals~~See ~~Management~~Item 2. ~~Segment~~Properties on page 38 in this Form 10-K for a list of the Contract Mining segment's locations and customers.

~~The~~ Minerals ~~Management segment derives income primarily by leasing our royalty~~ and ~~mineral~~Royalties 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.Segment

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

•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 have 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.

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~~operating~~The ~~expenses~~Minerals and ~~have~~Royalties ~~limited~~segment ~~environmental~~owns ~~liability;~~royalty ~~however~~interests, ~~ORRIs~~mineral ~~may~~interests, ~~be calculated net of post~~non-~~production~~participating ~~expenses,~~royalty ~~depending on how the ORRI is structured. ORRIs that are carved out of working~~ interests ~~are linked to the same underlying oil~~ and ~~gas~~overriding ~~lease~~royalty ~~that~~interests ~~created~~(collectively ~~the~~mineral ~~working interest,~~ and ~~therefore,~~royalty ~~such ORRIs are typically subject to expiration upon the expiration or termination of the oil and gas lease~~interests).

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

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

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

~~The~~During 2025 and 2024, the Minerals ~~Management~~and Royalties segment ~~does~~invested ~~not~~$15.0 ~~currently~~million ~~have~~and ~~any~~$16.6 ~~material~~million, ~~investments~~respectively, ~~under~~in Eiger Resources, which itholds ~~would~~operated beand ~~required~~non-operated toworking ~~bear~~interests in oil and natural gas assets in the ~~cost~~Kansas and the Oklahoma portion of ~~exploration,~~the ~~production~~Hugoton orbasin. ~~development~~Eiger Resources meets the definition of a VIE. ~~The~~NACCO ~~Minerals~~is ~~Management~~not ~~segment~~the ~~will~~primary ~~benefit~~beneficiary ~~from~~of the ~~continued~~VIE ~~development~~as it does not exercise financial control; therefore, we do not consolidate the results of these operations within our ~~mineral~~financial ~~properties~~statements. ~~without~~Instead, ~~the~~this ~~need~~investment is accounted for under the equity method. Our investment ofis ~~additional~~reported ~~capital~~on ~~once~~the ~~mineral~~line ~~and~~Equity ~~royalty~~method ~~interests~~investment ~~have~~in ~~been~~Eiger ~~acquired~~Resources asin the ~~capital~~Consolidated ~~costs~~Balance Sheets. Due to the timing and availability of financial information, earnings or ~~lease~~losses ~~operating~~from ~~expenses~~this investment are ~~born~~recorded ~~entirely~~on bya one quarter lag. See Note 1 to the ~~operators~~Consolidated orFinancial ~~working~~Statements ~~interest~~in ~~owners~~this Form 10-K for further information on Eiger Resources.

~~During~~Excluding ~~2024~~the ~~and~~Eiger ~~2023~~Resources investment described above, ~~Minerals~~total ~~Management~~consideration ~~invested~~for athe ~~total~~acquisitions of mineral and royalty interests was $194.16 million, ~~including~~and $150.7 million, in ~~the~~2025 ~~fourth~~and ~~quarter~~2024, ofrespectively. The 2025 acquisitions included 10.5 thousand gross acres and 0.4 thousand net royalty acres. The 2024 acquisitions include 13.7 thousand gross acres and 0.6 thousand net royalty acres.

~~2024,~~The inMinerals ~~Eiger,~~and ~~which~~Royalties ~~holds~~segment ~~non-operated~~also ~~working~~manages ~~interests~~legacy inroyalty ~~oil~~ and ~~natural~~mineral ~~gas~~interests ~~assets~~located in ~~the~~Ohio ~~Kansas~~(Utica and ~~the~~Marcellus ~~Oklahoma~~shale ~~portion~~natural ~~of the Hugoton basin. This entity meets the definition of a VIE. NACCO is not the primary beneficiary of the VIE as it does not exercise financial control; therefore~~gas), weLouisiana do(Haynesville ~~not~~shale ~~consolidate~~and ~~the~~Cotton ~~results~~Valley offormation ~~these~~natural ~~operations within our financial statements. Instead~~gas), ~~this~~Texas ~~contract~~(Cotton isValley ~~accounted~~and ~~for~~Austin asChalk anformation ~~equity~~natural ~~method investment. During 2024~~gas), weMississippi ~~recorded $0.6 million~~(coal), ~~which~~Pennsylvania ~~represented our share of earnings~~(coal, ascoalbed ~~Earnings~~methane ofand ~~unconsolidated~~Marcellus ~~operations~~shale onnatural ~~the~~gas), ~~Consolidated~~Alabama ~~Statements~~(coal, ofcoalbed ~~Operations.~~methane ~~Our~~and ~~investment~~natural isgas) ~~reported~~and onNorth ~~the~~Dakota ~~line Equity method investment in Eiger~~(coal, ~~LLC~~oil inand ~~the~~natural ~~Consolidated Balance Sheets~~gas). ~~Due~~The tomajority aof ~~lag~~our inlegacy ~~Eiger's~~reserves ~~financial~~were ~~reporting,~~acquired ~~earnings~~as orpart ~~losses~~of ~~from~~our ~~this~~historical ~~investment~~coal ~~will~~mining ~~be recorded on a one quarter lag~~operations.

~~Excluding~~Total ~~the~~oil ~~Eiger~~and ~~investment~~gas ~~described above, total consideration for the acquisitions of~~ mineral and royalty interests ~~was~~include $0approximately 208.70 ~~million~~thousand gross acres and ~~$36~~64.74 ~~million,~~thousand innet ~~2024~~royalty ~~and~~acres ~~2023~~at December 31, ~~respectively~~2025. ~~The~~Net ~~2024~~royalty ~~acquisitions~~acres ~~include~~are ~~13.7~~calculated ~~thousand~~based ~~gross~~on ~~acres~~our ownership and ~~0.6 thousand net~~ royalty ~~acres.~~rate, ~~The~~normalized ~~2023~~to ~~acquisitions~~a ~~included~~standard ~~43.4~~1/8th ~~thousand~~royalty ~~gross~~lease, ~~acres~~ and ~~2.5~~assumes ~~thousand~~a ~~net~~1/4th royalty rate for unleased acres.

WeSee ~~also~~Item 2. ~~manage~~Properties ~~legacy~~on ~~royalty~~page ~~and~~40 ~~mineral interests located~~ in ~~Ohio~~this ~~(Utica~~Form ~~and~~10-K ~~Marcellus~~for ~~shale~~discussion ~~natural~~of ~~gas),~~the ~~Louisiana~~Mineral ~~(Haynesville shale~~ and ~~Cotton~~Royalties ~~Valley~~segment's ~~formation~~proved natural gas), Texas (Cotton Valley and Austin Chalk formation natural gas), Mississippi (coal), Pennsylvania (coal, coalbed methane and Marcellus shale natural gas), Alabama (coal, coalbed methane and natural gas) and North Dakota (coal, oil and natural gas). The majority of our legacy reserves ~~were acquired as part of our historical coal mining operations~~.

Total oil and gas mineral and royalty interests include approximately 198.4 thousand gross acres and 63.9 thousand net royalty acres at December 31, 2024. Net royalty acres are calculated based on our ownership and royalty rate, normalized to a standard 1/8th royalty lease, and assumes a 1/4th royalty rate for unleased acres.

See Item 2. Properties on page 29 in this Form 10-K for discussion of our proved reserves.

Customers

The principal customers of the Coal Mining segment are electric utilities and an independent power provider.

The principal customers of the NAMining segment are limestone producers and to a lesser extent, sand and gravel producers. In addition, NAMining will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

The Minerals Management segment generates income primarily from royalty-based lease payments from oil, gas and to a lesser extent, coal producers. The pricing of oil, gas and coal sales is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As a mineral owner, we have limited access to timely information, involvement, and operational control over the volumes of oil, gas and coal produced and sold and the terms and conditions, including price, on which such volumes are marketed and sold.

In 2024 and 2023, three customers and two customers, respectively, accounted for more than 10% of consolidated revenue. The following represents the revenue attributable to each of these entities as a percentage of consolidated revenue for those years:

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	Percentage of Consolidated Revenues
Segment	2024		2023
Coal Mining customer	29	%	40	%
NAMining customer	24	%	22	%
NAMining customer	11	%	7	%

Customers

The principal customers of the Utility Coal Mining segment are electric utilities and an independent power provider.

The principal customers of the Contract Mining segment are limestone producers and to a lesser extent, construction firms and sand and gravel producers. In addition, the Contract Mining segment will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

The Minerals and Royalties segment generates income primarily from royalty-based lease payments from oil, gas and to a lesser extent, coal producers. The pricing of oil, gas and coal sales is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As a mineral owner, we have limited access to timely information, involvement, and operational control over the volumes of oil, gas and coal produced and sold and the terms and conditions, including price, on which such volumes are marketed and sold.

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


	Percentage of Consolidated Revenues
Segment	2025		2024
Utility Coal Mining customer	31	%	29	%
Contract Mining customer	25	%	24	%
Contract Mining customer	10	%	11	%

The loss of any of these customers could have a material adverse effect on the results of operations attributable to the applicable segment and on our consolidated results of operations.

Based on industry information, we believe we were one of the ten largest coal producers in the U.S. in 2025 and 2024.

Based on industry information, we believe that we were the largest dragline operator in the U.S. in 2025 and 2024.

Competition

Coteau, Coyote Creek, Falkirk and MLMC each have only one customer ~~for which they extract and deliver coal~~. Our coal mines are directly adjacent to our customer’s property, with economical delivery methods that include conveyor belt delivery systems linked to the customer’s facilities or short-haul rail systems. All of the mines in the Utility Coal Mining segment are the most economical suppliers to each of their respective customers as a result of transportation advantages over competitors. In addition, the customers' facilities were specifically designed to use the coal ~~being mined~~.

The coal industry competes with other sources of energy, particularly oil, gas, hydro-electric power and nuclear power., Inand, ~~addition~~to a lesser extent, itwind ~~competes~~and ~~with~~solar. ~~subsidized~~Natural ~~sources~~gas-fired power plants have the most potential to displace coal-fired electric baseload power generation in the near term. Fluctuations in natural gas prices and the availability of renewable energy, ~~primarily~~sources ~~wind~~can contribute to changes in power plant dispatch and ~~solar~~customer demand for coal. Among the factors that affect competition are the price and availability of oil and natural gas, ~~environmental~~our ~~and~~customers' ~~related~~dispatch ~~political considerations~~decisions, the time and expenditures required to develop ~~new~~ energy sources, the cost of transportation, the cost of compliance with governmental regulations, and the impact of federal and state energy policies~~, the impact of subsidies on pricing of renewable energy and our customers' dispatch decisions, which may also take into account carbon dioxide emissions~~. The ability of the Utility Coal Mining segment to maintain comparable levels of coal production at existing facilities and develop our reserves will depend upon the interaction of these factors.

~~Coal-fired~~The ~~electricity~~Contract ~~generating~~Mining ~~units~~segment ~~are~~faces ~~chosen~~competition tofrom ~~run~~producers ~~primarily~~of ~~based on operating costs~~aggregates, oflithium ~~which~~or ~~fuel~~other ~~costs~~minerals ~~account~~that ~~for~~choose ~~the largest share. Natural gas-fired power plants have the most potential~~ to ~~displace coal~~self-~~fired~~perform ~~electric~~mining ~~baseload~~operations ~~power generation in the near term. Federal~~ and ~~state mandates for increased use of electricity derived~~ from ~~renewable energy sources could also negatively affect demand for coal. Such mandates, combined with~~ other ~~incentives~~mining ~~to use renewable energy sources, such as tax credits, make alternative fuel sources more competitive with coal~~companies. Fluctuations in natural gas prices and the availability of renewable energy sources, particularly wind, can contribute to changes in power plant dispatch and customer demand for coal. Over the longer term, we continue to believe that customer demand will remain pressured by regulations mandating or incentivizing the purchase of power from subsidized renewable energy sources, particularly wind and solar. See Item 1. Business — Government Regulation on page 9 in this Form 10-K for further discussion. Environmental, social and governance considerations can also have an impact on power plant dispatch and demand for coal.

~~Based~~In onthe ~~industry~~Minerals ~~information~~and Royalties segment, wethe ~~believe~~oil and gas industry is intensely competitive; we ~~were~~primarily ~~one~~compete with companies and investors for the acquisition of oil and gas properties, some of which have greater resources and may be able to pay more for productive oil and natural gas properties or to define, evaluate, bid for and purchase a greater number of properties than our financial resources permit. Additionally, many of the ~~ten~~Minerals ~~largest~~and ~~coal~~Royalties ~~producers~~segment's competitors are, or are affiliated with, operators that engage in the Uexploration and production of their oil and gas properties, which allows them to acquire larger assets that include operated properties.S Larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. inThe ~~2024~~integrated ~~based~~competitors onmay ~~total~~also ~~coal~~have ~~tons~~a ~~produced~~better understanding of when minerals they acquire will be developed, as they are often the developer. The Minerals and Royalties segment’s ability to acquire additional properties in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly

NACCO believes that we were the largest dragline operator in the U.S. in 2024.

NAMining faces competition from producers of aggregates, lithium or other minerals that choose to self-perform mining operations and from other mining companies.

In the Minerals Management segment, the oil and gas industry is intensely competitive; we primarily compete with companies and investors for the acquisition of oil and gas properties, some of which have greater resources and may be able to pay more for productive oil and natural gas properties or to define, evaluate, bid for and purchase a greater number of properties than our financial resources permit. Additionally, many of the Minerals Management segment's competitors are, or are affiliated with, operators that engage in the exploration and production of their oil and gas properties, which allows them to acquire larger assets that include operated properties. Larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. The integrated competitors may also have a better understanding of when minerals they acquire will be developed, as they are often the developer. The Minerals Management segment’s ability to acquire additional properties in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business

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competitive environment. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

At Mitigation Resources, there are significant barriers to entry and the market is highly regulated; however, the markets we serve are highly fragmented and we compete with a number of regional companies. Some of these companies may have greater financial and other resources, while others may be smaller and more specialized and may concentrate their resources on specific areas of expertise. Our results are also affected by the number of competitors in a market, the demand for services in a particular market, the pricing practices of competitors and the entry of new competitors in a market.

Seasonality

We have experienced limited variability in our results due to the effect of seasonality; however, variations in coal demand can occur as a result of the timing and duration of planned or unplanned outages at our customers' facilities. Variations in coal demand can also occur as a result of changes in market prices of competing fuels such as natural gas, wind and solar power and demand for electricity, which can fluctuate based on changes in weather patterns. In addition, demand for coal-fired power generation can increase due to unusually hot or cold weather as consumers use more air conditioning or heating, respectively. Conversely, mild weather can result in weaker demand for coal-fired power generation.

The ~~NAMining~~Contract Mining segment extracts a significant amount of the annual limestone produced in Florida. The Florida construction industry can be affected by the cyclicality of the economy, seasonal weather conditions, and significant weather events, ~~and pandemics,~~ all of which can result in variations in demand for aggregates.

In the Minerals ~~Management~~and Royalties segment, oil and natural gas wells have high initial production rates and follow a natural decline before settling into relatively stable, long-term production. Decline rates can vary due to factors like well depth, well length, geology, formation pressure, and facility design. In addition to the natural production decline curve, royalty income can fluctuate favorably or unfavorably in response to a number of factors outside of our control, including the number of wells being operated by third parties, fluctuations in commodity prices (primarily oil and natural gas), fluctuations in production rates associated with operator decisions, regulatory risks, our lessees' willingness and ability to incur well-development and other operating costs, and changes in the availability and continuing development of infrastructure.

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices during the first and fourth quarters. ~~Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations.~~ Seasonal weather conditions can limit drilling and producing activities and other oil and natural gas operations. Due to these seasonal fluctuations, the Minerals ~~Management~~and Royalties segment's results of operations for individual quarterly periods may not be indicative of the results that may be ~~realize~~realized on an annual basis.

Human Capital

As of December 31, ~~2024~~2025, we had approximately 1,700 employees, including approximately 1,100 employees at our unconsolidated mining operations,. ~~none~~None of ~~which~~our employees are represented by a collective bargaining agreement. NACCO believes we have good relations with our employees.

Market-Based Compensation: We believe our employees are critical to our success and we invest in our employees by offering a market-based competitive total rewards package that includes a combination of salaries and wages and a benefits package that promotes employee well-being across all aspects of their lives. We offer a 100% 401(k) matching contribution up to 5% of compensation, which is immediately vested. We automatically enroll new employees in our 401(k) plan at a 5% deferral rate, and in 2024, we implemented a program to re-enroll current employees who were not deferring at least 5%. Additionally, NACCO offers a generous profit-sharing contribution for all of our full-time and part-time employees. We provide employee wages that are competitive and consistent with employee positions, skill levels, experience, knowledge and geographic location. Benefits offered to employees include:

•Medical, dental and vision benefits for employees, spouses and dependents;

•Flexible spending accounts for both healthcare and dependent care;

•Health savings accounts and health reimbursement accounts, ~~both~~certain of which receive company contributions;

•Paid vacation and holidays;

•Parental leave;

•Short-term and long-term disability benefits;

•Wellness incentives and programs for employees;

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•Life and AD&D insurance benefits;

•Identity protection benefits;

•Charitable donation matches; and

•Employee assistance program.

7Employee Development: We know that our people are our greatest asset and we recognize that our culture and success is strengthened when employees are respected, motivated and engaged. We work to match employees with assignments that capitalize on the skills, talents and potential of each employee, and we provide opportunities for professional growth. NACCO believes training is a critical component of employee well-being and growth. Training ranges from equipment-specific task training and enhanced safety procedures to strategic leadership and management training, ethics training and role-specific training. Employees are encouraged to pursue continued professional development, skills training and other educational opportunities. Qualified employees are eligible to participate in a tuition reimbursement program to advance their formal education. Internships are also available across our family of companies. We believe in hiring, engaging, developing and promoting people who are fully able to meet the demands of each position, regardless of race, color, religion, gender, sexual orientation, gender identity, national origin, age, veteran status or disability.

~~Table~~Safety: Employee safety in the workplace is one of ~~Contents~~our core values. We are committed to strict compliance with applicable laws and regulations regarding workplace safety and provide on-going safety training, education and communication. Safety performance is monitored through physical observations from both internal and external parties and through the reporting of key metrics. Our mining operations are regulated by the U.S. Mine Safety and Health Administration and non-mining operations are regulated by the U.S. Occupational Safety and Health Administration.

~~Employee~~During ~~Development:~~2025, Wean ~~recognize~~incident ~~that~~at ~~our~~a ~~culture~~quarry ~~and~~in ~~success~~Florida isresulted ~~strengthened~~in ~~when~~two ~~employees~~employee ~~are respected, motivated and engaged~~fatalities. WeThe ~~work~~event tois ~~match~~currently ~~employees~~under ~~with~~investigation ~~assignments~~by ~~that capitalize on~~ the ~~skills,~~U.S. ~~talents~~Mine ~~and~~Safety ~~potential of each employee,~~ and ~~provides~~Health ~~opportunities for professional growth~~Administration. ~~NACCO~~In ~~believes~~the ~~training~~aftermath ~~is a critical component~~ of ~~employee~~this ~~well-being~~incident, ~~and~~we ~~growth.~~are ~~Training~~reviewing ~~ranges~~ways ~~from~~to ~~equipment-specific~~further ~~task~~strengthen ~~training~~our ~~and enhanced~~ safety ~~procedures~~guidelines ~~to strategic leadership~~ and ~~management~~reinforce ~~training,~~our ~~ethics~~safety ~~training~~expectations ~~and~~across ~~role-specific~~the ~~training~~organization. ~~Employees~~Our employees are ~~encouraged~~the tonucleus ~~pursue~~of ~~continued~~NACCO’s ~~professional development~~success, ~~skills training~~ and ~~other~~their ~~educational~~safety ~~opportunities.~~will ~~Qualified~~always ~~employees~~come ~~are~~before ~~eligible~~all toelse. ~~participate~~We inmaintain ainsurance ~~tuition~~with ~~reimbursement~~respect ~~program~~ to ~~advance~~operating ~~their~~the ~~formal~~dragline ~~education.~~involved ~~We believe~~ in ~~hiring,~~this ~~engaging,~~incident ~~developing~~ and ~~promoting~~related ~~people~~liabilities ~~who~~(which are ~~fully~~subject ~~able~~ to ~~meet~~deductibles) ~~the~~and ~~demands~~believe ofthat ~~each~~our ~~position,~~insurance ~~regardless~~coverage ofwill ~~race,~~be ~~color,~~adequate ~~religion,~~to ~~gender,~~cover ~~sexual~~any ~~orientation, gender identity, national origin, age, veteran status or disability~~liabilities.

Safety: Employee safety in the workplace is one of our core values. We are committed to strict compliance with applicable laws and regulations regarding workplace safety and provides on-going safety training, education and communication. The National Mining Association ranks NACCO as an industry leader in safety, and our incident rate is consistently below the national average for comparable mines, based on Mine Safety and Health Administration data. We have earned more than 100 safety awards at the state and national levels since the 1980s. NACCO strives to have zero safety incidents or injuries. Our operations have ~~onsite~~ safety personnel who train employees in safe work practices, review safety-related incidents and recommend improvements when appropriate. Hazards in the workplace are actively identified and management tracks incidents so remedial actions can be taken to improve workplace safety. As part of our efforts to continuously improve our safety programs, NACCO’s safety professionals from across the organization meet regularly to share ideas and best practices. We believe communication related to ~~near~~safety ~~misses~~incidents, ~~safety~~near ~~incidents~~misses and protocols is essential to continuously developing and maintaining ~~best-practices~~robust ~~related~~safety topractices. ~~safety~~This ~~and~~communication also enables the identification and correction of operational practices that might impair employee safety or health. Every employee is responsible and accountable for safety performance.

Company Ethics: We have processes in place for compliance with our Code of Corporate Conduct, Insider Trading Policy and Anti-Corruption Policy. All of our Directors and employees annually complete certifications ~~with respect~~ to ~~compliance~~comply with our Code of Corporate Conduct. In addition, all of our employees are required to complete annual Code of Corporate Conduct training. The Code of Corporate Conduct, Insider Trading Policy and Anti-Corruption Policy require employees to comply with applicable laws and regulations, maintain high ethical standards and report situations of actual or potential noncompliance. The Company believes the code and these policies represent sound practices and provide a strong framework for the conduct of our Board and employees. All NACCO personnel are required to report without delay any conduct which they believe to be illegal or a violation of our policies. The identity of any NACCO personnel making such a report is kept in strict confidence except as required by law, and we utilize a third-party hotline to ensure reports can be generated anonymously. Retaliation in any form against an individual who exercises their right to make a complaint in good faith is strictly prohibited.

Community Engagement: We value our local communities and provide support through volunteer activities, financial contributions and well-paying jobs. NACCO believes in making long-term investments in the areas where we operate by supporting numerous charitable efforts, including educational, arts and community organizations. Community engagement is encouraged and supported through our matching gift program. We will match employee contributions up to $5,000 per employee if program criteria are met.

Please visit nacco.com/stewardship/ for the full text of certain NACCO stewardship policies.

Available Information

We make our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports available through our website, www.nacco.com, as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission (SEC). The content of our website is not incorporated by reference into this Form 10-K or in any other report or document filed with the SEC, and any reference to our website is intended to be an inactive textual reference only. The SEC maintains an internet site at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding us and other issuers that file electronically with the SEC.

Under Rule 12b-2 of the Exchange Act, we qualify as a smaller reporting company because our public float as of the last business day of our most recently completed second quarter was less than $250 million. For as long as we remain a smaller reporting company, we may take advantage of certain exemptions from the SEC’s reporting requirements that are otherwise applicable to public companies that are not smaller reporting companies.

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~~Government~~Available ~~Regulation~~Information

~~Our~~We ~~operations~~make ~~are~~our ~~subject~~annual toreports ~~various~~on ~~federal~~Form 10-K, ~~state~~quarterly ~~and~~reports ~~local~~on ~~laws~~Form ~~and~~10-Q, ~~regulations~~current reports on ~~matters~~Form ~~such~~8-K asand ~~employee~~any ~~health~~amendments ~~and~~to ~~safety~~those reports available through our website, ~~and~~www.nacco.com, ~~certain~~as ~~environmental~~soon ~~laws~~as ~~and~~reasonably ~~regulations~~practicable ~~relating~~after tosuch material is electronically filed with, ~~among~~or ~~other~~furnished ~~matters~~to, the ~~reclamation~~Securities and ~~restoration~~Exchange Commission (SEC). The content of ~~coal~~our ~~mining~~website ~~properties,~~is ~~air~~not ~~pollution,~~incorporated ~~water~~by ~~pollution,~~reference ~~the~~into ~~disposal~~this ofForm ~~wastes~~10-K ~~and~~or ~~effects~~in onany ~~groundwater.~~other Inreport ~~addition,~~or document filed with the ~~electric~~SEC, ~~power~~and ~~generation~~any ~~industry~~reference to our website is ~~subject~~intended to ~~extensive~~be ~~regulation~~an ~~regarding~~inactive ~~the~~textual ~~environmental~~reference ~~impact~~only. ofThe ~~its~~SEC ~~power~~maintains ~~generation~~an ~~activities~~internet site at http://www.sec.gov that ~~could~~contains ~~affect~~reports, ~~demand~~proxy ~~for~~and ~~coal~~information ~~from~~statements, ~~our~~and ~~Coal~~other ~~Mining~~information ~~segment~~regarding us and other issuers that file electronically with the SEC.

~~Numerous~~Under ~~federal,~~Rule ~~state~~12b-2 ~~and~~of ~~local~~the ~~governmental~~Exchange ~~permits~~Act, ~~and~~we ~~approvals~~qualify ~~are~~as ~~required~~a ~~for~~smaller ~~coal~~reporting ~~mining~~company ~~operations.~~because ~~Our~~our ~~subsidiaries~~public ~~hold~~float oras ~~will~~of ~~hold~~ the ~~necessary~~last ~~permits~~business atday ~~all~~ of our ~~lignite~~most ~~coal~~recently ~~mining~~completed ~~operations.~~second Atquarter ~~the~~was ~~coal~~less ~~mining~~than ~~operations~~$250 ~~where~~million. ~~our~~For ~~subsidiaries~~as ~~hold~~long ~~the~~as ~~permits,~~ we ~~are~~remain ~~required~~a tosmaller ~~prepare~~reporting ~~and present to federal~~company, ~~state~~we ormay ~~local~~take ~~governmental~~advantage ~~authorities~~of ~~data~~certain ~~pertaining~~exemptions tofrom the ~~effect~~SEC’s orreporting ~~impact~~requirements that ~~any~~are ~~proposed~~otherwise ~~exploration~~applicable ~~for~~to orpublic ~~production~~companies ofthat ~~coal~~are ~~may~~not ~~have~~smaller ~~upon~~reporting ~~the environment and public and employee health and safety~~companies.

~~Many~~Government ~~aspects~~Regulation ~~of the production, pricing~~ and ~~marketing~~Environmental of oil and natural gas are regulated by federal and state agencies. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, which frequently increases the regulatory burden on affected members of the industry and could affect the results of Minerals Management segment.Matters

Operations on our properties, projects and mineral interests must be conducted in compliance with all applicable federal, state and local laws and regulations. These laws and regulations include matters involving the discharge of materials into the environment, employee health and safety, permits and other licensing requirements, reclamation and restoration of properties, management of materials, air quality, water quality, limitations on land use as well as the protection of wetlands, plant and wildlife. These laws and regulations, which are extensive and subject to change, could have a significant effect on our production costs and our competitive position. While it is not possible to quantify the costs of compliance with all applicable federal, state and local laws and regulations, those costs could be significant.

Future legislation, regulations or orders, as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders, may result in substantial increases in equipment and operating costs and delays, interruptions, or a termination of operations, the likelihood or extent of which we cannot predict. We intend to continue to comply with regulatory requirements as they evolve by timely implementing necessary modifications and/or operating procedures.

The following is a summary of the more significant existing government regulations and environmental matters to which we or our customers'/lessees' business operations are subject and for which compliance may have a material adverse effect on our business, results of operations and financial condition. For additional information regarding our material risks, please refer to Item 1A - Risk Factors on page 15.

Mine Health and Safety Laws

The Federal Mine Safety and Health Act of 1977 imposes safety and health standards on all mining operations. Regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters. The Federal Mine Safety and Health Administration enforces compliance with these federal laws and regulations.

Environmental Laws

Our ~~coal mining~~ operations are subject to various federal environmental laws, as amended, including:

•the Surface Mining Control and Reclamation Act of 1977 (SMCRA);

•the Clean Air Act, including amendments to that act in 1990 (CAA);

•the Clean Water Act of 1972 (CWA);

•the Resource Conservation and Recovery Act (RCRA);

•the National Environmental Policy Act of 1970 (NEPA); and

•the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA).

In addition to these federal environmental laws, various states have enacted environmental laws that provide for higher levels of environmental compliance than similar federal laws. These state environmental laws require reporting, permitting and/or approval of many aspects of ~~coal mining~~ operations. ~~Both federal and state inspectors regularly visit mines to enforce compliance.~~ We have ongoing training, compliance and permitting programs to ensure compliance with such environmental laws. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect ~~the~~our ~~Coal Mining segment~~business.

~~The~~Surface ~~election~~Mining ofControl ~~Donald Trump, paired with Republican control of Congress, is likely to have a significant~~ and ~~favorable~~Reclamation ~~impact~~Act on the regulatory environment, particularly for fossil fuels. President Trump issued an Executive Order on January 20, 2025, "Unleashing American Energy," directing all federal executive agency heads to review all agency actions implicating energy reliability and affordability or potentially burdening the development of domestic energy resources. It is not yet clear how existing regulations affecting existing fossil fuel assets will be reconsidered or repealed. (SMCRA)

~~Surface~~SMCRA ~~Mining~~establishes ~~Control~~mining, environmental protection and ~~Reclamation~~reclamation ~~Act~~standards for all aspects of surface coal mining operations. SMCRA stipulates compliance with many other major environmental programs. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the primary regulatory authority.

SMCRA establishes mining, environmental protection and reclamation standards for all aspects of surface coal mining operations. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the primary regulatory authority.

Coal mine operators must obtain SMCRA permits and permit renewals for coal mining operations from the applicable regulatory agency. These SMCRA permit provisions include requirements for coal prospecting, mine plan development, topsoil removal, storage and replacement, selective handling of overburden materials, mine pit backfilling and grading, protection of the hydrologic balance, surface drainage control, mine drainage and mine discharge control and treatment, and revegetation. Although mining permits have stated expiration dates, SMCRA provides for a right of successive renewal. The cost of obtaining surface mining permits can vary widely depending on the quantity and type of information that must be provided to obtain the permits.

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~~SMCRA~~Coal ~~establishes~~mine ~~operational,~~operators ~~reclamation~~must obtain SMCRA permits and ~~closure~~permit ~~standards~~renewals for ~~surface~~ coal ~~mines~~mining operations from the applicable regulatory agency. WeThese ~~accrue~~SMCRA ~~for~~permit ~~the~~provisions ~~costs~~include ofrequirements ~~final~~for coal prospecting, mine ~~closure~~plan development, ~~including~~topsoil ~~the~~removal, ~~cost~~storage and replacement, selective handling of ~~treating~~overburden materials, mine ~~water~~pit ~~discharges~~backfilling and grading, atprotection ~~mines~~of ~~where~~the ~~our~~hydrologic ~~subsidiaries~~balance, ~~hold~~surface ~~the~~drainage ~~mining~~control, ~~permit~~mine drainage, mine discharge control and treatment and revegetation. ~~While~~Although ~~these~~mining ~~obligations~~permits ~~are~~have ~~largely~~stated ~~unfunded~~expiration dates, ~~they~~SMCRA ~~can~~provides ~~require~~for ~~securitization~~a ~~through~~right ~~bonding,~~of ~~with~~successive ~~the~~renewal. ~~exception~~The cost of ~~the~~obtaining ~~final~~surface ~~mine~~mining ~~closure~~permits ~~costs~~can ~~for~~vary widely depending on the ~~Coyote~~quantity ~~Creek~~and ~~Mine,~~type ~~which~~of ~~are~~information ~~being~~that ~~funded~~must ~~throughout~~be ~~the~~provided ~~production~~to ~~stage~~obtain the permits.

SMCRA ~~stipulates~~establishes ~~compliance with many other major environmental programs~~operational, ~~including~~reclamation ~~the CAA~~ and ~~CWA.~~closure ~~The~~standards ~~U.S.~~for ~~Army~~surface ~~Corps~~coal ofmines. ~~Engineers~~We ~~regulates~~accrue ~~activities~~for ~~affecting navigable waters, and~~ the ~~U.S.~~costs ~~Bureau~~ of ~~Alcohol,~~final ~~Tobacco~~mine ~~and~~closure, ~~Firearms~~including ~~regulates~~ the ~~use~~cost of ~~explosives~~treating ~~for~~mine ~~blasting.~~water ~~In addition~~discharges, ~~the~~at ~~U.S.~~mines ~~Environmental~~where ~~Protection~~our ~~Agency~~businesses ~~(the~~hold ~~EPA),~~ the Umining permit.S. ~~Army~~While ~~Corps~~these ofobligations ~~Engineers~~are ~~and~~largely ~~the~~unfunded, ~~Office~~they ofcan ~~Surface~~require ~~Mining~~securitization ~~Reclamation~~through ~~and~~bonding, ~~Enforcement~~with ~~(OSMRE)~~the ~~have~~exception ~~engaged in a series~~ of ~~rulemakings~~the ~~and~~final ~~other~~mine ~~administrative~~closure ~~actions~~costs ~~under~~for the ~~CWA~~Coyote ~~and~~Creek ~~other~~Mine, ~~statutes~~which ~~that~~ are ~~directed~~being atfunded ~~reducing~~by the ~~impact~~customers ofthroughout ~~coal~~the ~~mining~~production ~~operations on water bodies~~stage.

~~Greenhouse~~Clean ~~Gas~~Air Act (~~GHG~~CAA) and Air Emissions

The process of burning coal and drilling for oil and natural gas can cause many compounds and impurities ~~in the coal~~ to be released into the air, including sulfur dioxide, nitrogen oxides, ~~(NOx)~~methane, mercury, particulates and other matter. Federal and state laws that extensively regulate the emissions of materials into the air affect ~~coal~~our ~~mining~~ operations both directly and indirectly. Direct impacts on ~~coal mining~~ operations can occur through permitting requirements and/or emission control requirements relating to air contaminants, especially particulate matter. Indirect impacts on ~~coal mining~~ operations can occur through regulation of the air emissions of sulfur dioxide, nitrogen oxides, methane, mercury, particulate matter and other compounds ~~emitted by coal-fired power plants~~.

In Greenhouse ~~May~~Gas ~~2024,~~(GHG) ~~the~~Emissions ~~EPA~~and ~~published~~ the ~~final~~Mercury ~~rules for GHG emissions~~ and ~~Mercury~~ Air Toxics Standards (MATS) ~~in the Federal Register. The final MATS and GHG rules will require compliance as early as 2027 and 2032, respectively.~~

Previous efforts by the EPA were met with extensive litigation and there has been a similar response to the new GHG and MATS rules. State coalitions have filed lawsuits challenging both of these rules. Several other entities, including electric generators and industry groups, have joined the lawsuits. In ~~July~~May 2024 ~~and October 2024~~, ~~stay motions for~~ the ~~GHG~~Environmental ~~and~~Protection ~~MATS~~Agency ~~rules were denied by the U.S. Court of Appeals for the District of Columbia Circuit~~ (~~the D.C. Circuit Court~~EPA), ~~respectively.~~published ~~Following~~ the ~~D.C.~~final ~~Circuit~~rules ~~Court denial, emergency stay motions were filed~~ for ~~the~~ GHG emissions and MATS ~~rules~~in ~~with~~ the ~~Supreme~~Federal ~~Court of the United States (SCOTUS)~~Register. InThe ~~October~~GHG ~~2024,~~standards ~~the~~are ~~SCOTUS~~based ~~denied~~on ~~the~~technologies ~~stay~~such ~~applications~~as ~~for~~carbon ~~the~~capture ~~GHG~~ and ~~MATS~~sequestration/storage ~~rules. The GHG~~ and ~~MATS~~natural ~~cases~~gas ~~continue~~co-firing. ~~through~~The ~~the~~compliance ~~normal~~deadline ~~procedures~~for inexisting ~~the~~coal-fired, ~~D.C.~~steam ~~Circuit~~generating ~~Court~~electric ~~without~~generating ~~stays~~units in(EGUs) ~~place.~~planning Onto ~~February~~install ~~19,~~carbon ~~2025,~~capture ~~the~~and ~~D.C.~~sequestration/storage ~~Circuit~~technology ~~granted~~has anbeen ~~EPA~~extended ~~motion~~ to ~~hold~~January ~~the~~1, ~~GHG~~2032 ~~case~~for inplants ~~abeyance~~that ~~for~~intend 60to ~~days~~operate ~~while~~beyond ~~the~~2039. ~~new~~If ~~EPA~~a ~~evaluates~~coal-fired ~~its~~plant ~~position~~intends onto ~~the~~close ~~GHG~~prior ~~rule.~~to ~~Similarly~~2032, onno ~~February~~controls ~~20,~~will ~~2025,~~be ~~the~~required ~~D.C.~~and ~~Circuit~~if ~~granted~~a anplant ~~EPA~~plans ~~motion~~ to ~~hold~~close ~~the~~between ~~MATS~~2032 ~~case in abeyance~~ and ~~removing~~2039, ~~the~~they ~~case~~must ~~from~~begin ~~the~~co-firing ~~upcoming~~with ~~oral~~natural ~~argument~~gas ~~calendar~~by ~~while~~January ~~the~~1, ~~new~~2030. ~~EPA~~The ~~evaluates its position on the~~ MATS ~~rule.~~rules Wefinalize ~~cannot~~changes ~~predict~~for the ~~full~~filterable ~~impact~~particulate ofmatter ~~the~~surrogate ~~MATS~~emission ~~and~~standard ~~GHG~~for ~~rules~~non-mercury onmetal ~~the~~hazardous ~~operations~~air ofpollutants ~~the~~for existing coal-fired ~~generation facilities operated by our customers; however~~EGUs, if the ~~rules~~filterable goparticulate ~~into~~matter ~~effect,~~emission ~~the~~standard ~~additional~~ compliance ~~costs~~demonstration ~~could~~requirements ~~have~~and athe ~~material~~mercury ~~adverse~~emission ~~effect~~standard onfor ~~our~~lignite-fired ~~Coal Mining segment~~EGUs.

~~The~~In ~~GHG~~2023, ~~standards~~the ~~are~~EPA ~~based~~issued onits ~~technologies~~methane ~~such~~rules asthat ~~carbon~~establish ~~capture~~new source and ~~sequestration/storage~~first-time ~~and~~existing ~~natural~~source ~~gas~~standards ~~co-firing.~~of ~~The~~performance ~~compliance~~for ~~deadline~~GHG and volatile organic compound emissions for ~~existing~~crude ~~coal-fired~~oil and natural gas well sites, ~~steam~~natural ~~generating~~gas ~~electric~~gathering ~~generating~~and ~~units~~boosting ~~(EGUs)~~compressor ~~planning~~stations, tonatural ~~install~~gas ~~carbon~~processing ~~capture~~plants, and ~~sequestration/~~transmission and storage ~~technology~~facilities. ~~has~~The ~~been~~EPA ~~extended~~also tofinalized ~~January~~a 1,Waste ~~2032~~Emissions ~~for~~Charge ~~plants~~implementation ~~that~~rule ~~intend~~in toNovember ~~operate~~2024; ~~beyond~~however, ~~2039.~~the IfCongressional aReview ~~coal-fired~~Act ~~plant~~was ~~intends~~used to ~~close~~disapprove ~~prior~~EPA’s toimplementation ~~2032~~rule in March 2025. As a result, no ~~controls~~methane ~~will~~emission befees ~~required~~are ~~and~~being ifassessed aor ~~plant~~collected. ~~plans~~In toNovember ~~close~~2025, ~~between~~the ~~2032~~EPA ~~and~~announced ~~2039,~~a ~~they~~final ~~must~~rule ~~begin~~to ~~co-firing~~extend ~~with~~several ~~natural~~compliance ~~gas~~deadlines byfor ~~January~~the 1,oil ~~2030~~and gas industry.

The ~~MATS~~EPA ~~rules~~under ~~finalize~~the ~~changes~~Trump ~~for~~Administration ~~the~~has ~~filterable~~made ~~particulate~~efforts ~~matter~~to ~~surrogate~~repeal ~~emission~~or ~~standard~~otherwise ~~for~~modify ~~non-mercury~~GHG ~~metal~~and ~~hazardous~~MATS ~~air~~regulations ~~pollutants~~at ~~for~~the ~~existing~~federal ~~coal-fired~~level. ~~EGUs~~On June 11, ~~the~~2025, ~~filterable~~EPA ~~particulate~~announced ~~matter~~a ~~emission~~plan ~~standard~~to ~~compliance~~repeal ~~demonstration~~the ~~requirements,~~GHG ~~and~~rule ~~the~~but ~~mercury~~has ~~emission~~not ~~standard~~yet ~~for~~published ~~lignite-fired~~a ~~EGUs.~~final ~~Review~~repeal of the ~~MATS~~rule. ~~rules~~On ~~indicate~~February ~~that~~12, 2026, the EPA ~~significantly~~revoked ~~reduced~~ the ~~fine~~2009 ~~particulate~~Endangerment ~~matter~~Finding, ~~emission~~which ~~standard~~found ~~for~~that ~~all~~six ~~existing~~GHGs ~~coal-fired~~endanger ~~EGUs~~public ~~and~~health, ~~will~~thus ~~require~~removing ~~continuous~~the ~~monitoring~~EPA’s ~~equipment~~authority to ~~demonstrate~~regulate ~~compliance~~GHGs. ~~Furthermore~~Additionally, on February 23, 2026, the EPA ~~elected~~repealed tothe ~~remove~~MATS rule. If not repealed, the ~~lignite~~2024 ~~subcategory~~GHG ~~for~~rule ~~mercury~~will ~~limits~~require compliance at our customers' facilities as early as 2029 and 2032. We cannot predict whether such efforts will ~~require~~ultimately ~~lignite-fired~~be ~~EGUs~~successful toor ~~meet~~what effects they may have on our business or results of operations and on the ~~same~~business ~~standard~~and asresults ~~other~~of ~~types~~operations of ~~coal.~~our customers/lessees.

~~The~~At ~~recent~~the ~~change~~same intime, ~~presidential~~many ~~administrations~~states, ~~recent executive actions~~regions, and ~~the~~governmental ~~resulting~~bodies ~~changes~~have atadopted ~~the~~or ~~EPA~~are ~~make~~considering itpolicies ~~unclear~~that ~~whether~~regulate ~~the~~greenhouse ~~promulgated~~gas ~~GHG~~emissions, including imposing fees or ~~MATS~~taxes ~~Rules~~on ~~will~~emissions befrom ~~enforced~~certain facilities such as coal‑fired power plants through cap‑and‑trade programs, ~~revised~~carbon taxes, or ~~repealed.~~climate ~~The~~“superfund” ~~various~~laws. ~~parties~~Other states are ~~working~~advancing ~~through~~plans to expand renewable energy use, which may further reduce the ~~legal~~role of coal and ~~administrative~~other ~~processes~~fossil fuels. Depending on future federal or state regulatory actions and the ~~actual~~outcomes ~~outcome~~of ~~remains~~potential ~~unknown~~legal atchallenges, ~~this~~demand ~~time.~~for coal, oil, and natural gas could decline, adversely affecting our operations.

The CAA requires the EPA to review national ambient air quality standards (NAAQS) every five years to determine whether revisions to current standards are 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

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~~revisions.~~ National ~~When~~Ambient ~~the~~Air ~~EPA~~Quality ~~adopts~~Standards 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. Our 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. On May 6, 2024, the EPA lowered the level for particulate matter by 25%. States are required to update their state implementation plans by February 2027. The rule is currently being challenged at the D.C. Circuit by a coalition of states led by Kentucky and West Virginia. Oral argument was held at the D.C. Circuit on December 16, 2024.

InThe ~~2011,~~CAA requires the EPA ~~finalized~~to ~~the~~set ~~Cross-State~~NAAQS ~~Air~~for ~~Pollution~~certain ~~Rule~~air ~~(CSAPR)~~pollutants. toThe ~~address~~EPA ~~interstate~~has ~~transport~~set ofNAAQS ~~pollutants~~for ozone, particulate matter, sulfur dioxide, nitrogen oxides, carbon monoxide and lead. ~~While~~Over the ~~CSAPR~~years, ~~affects~~the ~~states~~EPA inhas made the ~~eastern~~NAAQS ~~half~~more ofstringent. Each state must develop a plan to be approved by the ~~U.S.~~EPA for achieving and ~~Texas~~maintaining NAAQS within its borders. These plans impose limits on emissions from pollution sources, itincluding ~~does~~fossil fuel-fired plants. Areas meeting NAAQS are designated as attainment areas. Areas not ~~affect~~meeting ~~EGUs~~NAAQS are designated as non-attainment areas, and more stringent requirements apply in ~~North~~those ~~Dakota.~~areas, ~~This~~including ~~rule~~stricter ~~imposes~~controls on industrial facilities and more complicated and public permitting processes.

~~additional~~During ~~emission~~2024, ~~restrictions~~the onEPA ~~coal~~finalized more stringent NAAQS for particulate matter that may increase the likelihood of certain areas being designated as non-~~fired~~attainment ~~power~~areas. ~~plants~~The more stringent NAAQS are currently subject to ~~attain~~a ~~ozone~~legal ~~and~~challenge ~~fine~~seeking to overturn the standards, but the challenge is currently being held in abeyance. On March 12, 2025, the EPA announced that it would be reconsidering the NAAQS for particulate matter and that it would release guidance to increase flexibility on NAAQS implementation and direction on permitting obligations. ~~The~~We ~~EPA~~are ~~began~~currently unable to predict any specific changes or how such changes, if any, may impact our operations.

~~implementation~~Cross-State ofAir ~~the~~Pollution ~~rule~~Rule ~~in 2015, when Phase I emission reductions in sulfur dioxide and nitrogen dioxide became effective.~~(CSAPR)

In ~~2019~~2011, ~~certain states submitted SIPs to~~ the EPA infinalized ~~response to~~ the ~~2015~~CSAPR ~~ozone~~to ~~standard~~address ~~reduction.~~interstate Ontransport ~~February~~of ~~13, 2023, the EPA rejected the SIPs~~pollutants. ~~The~~While ~~EPA’s action to deny~~ the ~~SIPs~~CSAPR ~~was~~affects ~~challenged~~states in ~~various courts, including~~ the ~~5th~~eastern ~~Circuit~~half ~~Court~~ of ~~Appeals (~~the ~~Fifth Circuit)~~U.S. ~~The~~and ~~Fifth Circuit issued a stay of the SIP rejection in~~ Texas, ~~Louisiana,~~it ~~and~~does ~~Mississippi~~not ~~which~~affect ~~prevents~~EGUs ~~the~~in ~~federal~~North ~~implementation~~Dakota. ~~plan~~This ~~(FIP)~~rule ~~from going into effect pending the outcome of the litigation challenges.~~ imposes

On June 5, 2023, the EPA published the FIP in the Federal Register. The 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. On July 31, 2023, the EPA promulgated an interim 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.~~restrictions ~~The~~on ~~Interim~~coal-fired ~~FIP maintains the state emissions budgets, unit level allowance allocation provisions, and banked allowance holdings reflecting the status quo for the~~ power plants into ~~these~~attain ~~states~~ozone ~~under~~and ~~the~~fine ~~Group~~particulate ~~2 trading program~~NAAQS.

In ~~June 2024~~2023, the ~~SCOTUS~~EPA ~~decided~~published ~~to stay~~ the ~~rule~~Good ~~pending~~Neighbor ~~further~~Plan, ~~review~~which ondecreases, ~~the~~over ~~merits~~time, ~~because~~ the ~~EPA's~~ozone-season ~~justifications~~NOx ~~were~~allowances ~~flawed.~~for ~~The~~EGUs ~~Ozone Transport Rule was premised on its applicability to 23 states, but litigation resulted~~ in the ~~removal~~affected ~~of 12 of those~~ states ~~that~~by ~~accounted~~assuming ~~for over 70 percent of the emissions the EPA had planned to address. The EPA purported to select control measures~~ that ~~would~~participants ~~maximize cost effectiveness~~ in ~~achieving~~this ~~downwind~~cap-and-trade ~~ozone~~program ~~air~~had ~~quality~~or ~~improvements, but it did so based on an assumption that all 23 states~~ would ~~apply~~optimize ~~the~~existing ~~uniform~~NOx ~~levels~~controls ofand ~~controls~~later ~~required~~install byadditional ~~the~~NOx ~~FIP~~controls. ~~The~~In ~~case~~2024, ~~was remanded to~~ the DU.CS. ~~Circuit~~Supreme ~~where~~Court ~~the~~(SCOTUS) ~~parties~~decided ~~fully briefed the case. Subsequent~~ to ~~briefing,~~stay the ~~EPA~~Good ~~asked~~Neighbor toPlan ~~partially~~pending ~~remand~~further ~~the rule to "take a supplemental final action addressing the record deficiency preliminarily identified by the Supreme Court~~review." ~~The~~In ~~EPA~~March ~~finalized the supplemental response in December 2024. On February 6,~~ 2025, the EPA ~~filed~~announced a ~~motion~~rollback ~~requesting abeyance~~ of ~~litigation~~the ~~for~~Good 60Neighbor ~~days~~Plan, toleaving ~~allow~~in aplace ~~transition~~pre-Good toNeighbor ~~the~~Plan ~~new~~requirements ~~administration~~from CSAPR. OnAdditional ~~February~~emission ~~21,~~restrictions ~~2025,~~under the ~~D.C.~~CSAPR ~~Circuit~~or ~~denied~~ the ~~EPA's~~Good ~~request~~Neighbor toplan ~~hold~~would increase the ~~litigation~~cost inof ~~abeyance~~operating ~~and extending~~ the ~~briefing~~customer ~~schedule~~facility ~~through~~serviced ~~March~~by ~~27, 2025~~MLMC.

~~Should~~ Regional the 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. We cannot predict the outcome of the legal challenges to the: (i) various state challenges; (ii) the FIP promulgated on June 5, 2023; (iii) the interim final rule promulgated on July 31, 2023; nor (iv) the supplemental response dated December 10, 2024 that seeks to address the judicial orders. If the original FIP withstands legal challenge, it would increase the cost of operating the customer facility serviced by MLMC.Haze

The EPA promulgated a regional haze program designed to protect and to improve visibility at and around Class I Areas, which are generally National Parks, National Wilderness Areas and International Parks. State implementation of the EPA’s Regional Haze Rule could require our North Dakota customers to incur significant new costs at their respective power plants, which could result in the premature closure of such power plants and their associated mines. The North Dakota Department of Environmental Quality (NDDEQ) finalized its state implementation plan and submitted it to the EPA for approval in August 2022. The NDDEQ determined that visibility progress was being made and did not require significant emissions controls at the North Dakota power plants. In ~~July~~ 2024, the EPA issued a proposed partial denial of the North Dakota state implementation plan. WeIn ~~submitted~~May ~~comments~~2025, to the EPA ongranted ~~the~~an ~~proposed~~administrative ~~partial~~petition ~~denial~~for ~~during~~ the ~~third~~EPA ~~quarter~~to ofreconsider ~~2024 and have filed~~ a ~~petition~~portion ~~for~~of ~~review with~~ the ~~Eight~~Clean ~~Circuit~~Air ~~Court~~Act’s ofregional ~~Appeals.~~haze ~~The~~rule ~~State~~which ofdisapproved North Dakota,'s ~~several~~state ofimplementation ~~our customers, and others have also filed petitions for review~~plan. On ~~February~~a 27broader scale, in March 2025, the EPA ~~filed~~announced anit ~~unopposed~~was ~~motion~~reconsidering toits ~~hold~~implementation ~~these~~of ~~consolidated~~the ~~cases~~Regional inHaze ~~abeyance~~Program ~~for~~and ~~120~~intends ~~days~~to ~~while~~review ~~the~~and ~~new~~revise ~~administration~~the ~~evaluates~~regulations ~~its~~to ~~position~~streamline on the ~~partial~~program ~~denial~~and ofchange ~~the~~compliance ~~state~~expectations. ~~implementation~~We ~~plan.~~are ~~Notwithstanding~~currently ~~NDDEQ’s~~unable ~~determination,~~to ~~the~~predict ~~EPA~~any ~~may~~specific ~~require~~changes ~~additional~~or ~~costly~~how ~~emission~~such ~~controls~~changes, ~~and~~if itany, may ~~not~~impact beour operations.

Clean Water Act (CWA)

The CWA affects certain of our operations by establishing in-stream water quality standards and treatment standards for wastewater discharge, including from coal mines.

In many instances, mining operations require securing CWA authorization or a permit from the U.S. Army Corps of Engineers (USACE) for operations in waters of the United States (WOTUS.) In 2023, the SCOTUS issued a decision in the case of Sackett v. Environmental Protection Agency, addressing the definition of WOTUS with regards to the CWA. The decision provides a clear standard that substantially restricts the USACE and the EPA’s ability to regulate certain types of wetlands and streams. Specifically, wetlands that do not have a continuous surface connection with traditional interstate navigable water are not federally jurisdictional. As a result of the Sackett decision, the EPA and the USACE revised the definition of WOTUS and promulgated a final rule. The new rule did 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 challenges to this rule have resumed. In November 2025, the EPA and the USACE proposed a new definition of WOTUS that contemplates a substantially narrower jurisdiction. We are currently unable to predict any specific changes or how such changes, if any, may impact our operations.

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~~economically~~Protection ~~feasible~~that ~~for~~it ~~our~~was ~~North~~required ~~Dakota~~to ~~customers~~establish toa ~~invest~~mine inwater ~~such~~treatment ~~equipment,~~trust ~~which~~to ~~could~~serve ~~result~~as ina ~~early~~long-term ~~retirement~~funding ofmechanism ~~our~~related ~~customers'~~to ~~power~~this ~~plants~~obligation. See Note 7 and ~~our~~Note ~~associated~~9 ~~mines~~to the Consolidated Financial Statements in this Form 10-K for further information on Bellaire.

~~Substantially~~Resource ~~all~~Conservation ~~of the Coal Mining segment's profits are derived from long-term mining contracts. These new rules may raise the cost of fossil fuel generated energy, making coal-fired power plants less competitive,~~ and~~/or~~ ~~result~~Recovery inAct early closure of the coal-fired EGU's operated by our customers 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 our coal mines. We cannot predict the full impact of the various GHG and CAA rules on the operations of the coal-fired EGUs operated by our customers and any early closure of our mines could have a material adverse effect on our business, financial condition and results of operations. (RCRA)

The ~~Trump~~RCRA ~~administration~~affects iscoal ~~expected~~mining tooperations ~~direct~~by ~~the~~establishing ~~EPA~~requirements tofor ~~reconsider~~the ~~and~~treatment, ~~revise~~storage orand ~~rescind~~disposal ~~the~~of ~~EPA’s~~wastes, ~~rules~~including ~~regulating~~hazardous ~~emissions~~wastes. ~~from~~Coal ~~power~~mine ~~plants~~wastes, ~~among~~such ~~other~~as ~~regulatory~~overburden ~~actions~~and ~~affecting~~coal ~~power~~cleaning ~~generation~~wastes, ~~and~~currently ~~has~~are ~~already~~exempted ~~issued~~from ~~executive~~hazardous ~~orders~~waste ~~aimed at this outcome~~management. ~~President~~In ~~Trump issued an Executive Order on January 20~~2020, ~~2025,~~the ~~"Unleashing~~EPA ~~American~~finalized ~~Energy,"~~changes ~~directing all federal executive agency heads~~ to ~~review~~the ~~all~~coal ~~agency~~combustion ~~actions~~residual ~~implicating~~(CCR) ~~energy~~rule ~~reliability~~that ~~and~~classified ~~affordability~~all orclay-lined ~~potentially~~surface ~~burdening~~impoundments ~~the~~that ~~development~~receive ofCCR ~~domestic~~as ~~energy resources~~unlined. ItThe isEPA ~~not~~also ~~yet~~established ~~clear~~alternative ~~how~~deadlines ~~existing~~to ~~regulations~~cease ~~affecting~~receipt ~~existing~~of ~~fossil~~waste ~~fuel~~to ~~assets~~include ~~will~~new besite-specific ~~reconsidered~~alternatives ordue ~~repealed.~~to ~~Although~~lack weof ~~anticipate~~disposal ~~the~~capacity ~~EPA’s~~with ~~review~~a ofdeadline ~~such~~to ~~regulations~~initiate ~~likely~~closure ~~will~~and ~~result~~a innew ~~less~~site-specific ~~stringent~~alternative ~~requirements,~~due weto ~~cannot~~permanent ~~predict~~cessation ~~the outcome~~ of ~~any~~coal-fired ~~final~~boilers ~~EPA~~with ~~actions~~deadlines ~~or court challenges~~ to ~~such~~complete ~~final actions~~closure.

Clean Water Act

CWA affects coal mining operations by establishing in-stream water quality standards and treatment standards for wastewater

discharge, including from coal mines.

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.) On May 25, 2023, the SCOTUS issued its Sackett vs. EPA ruling that defined 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.” As a result of the Sackett decision, the EPA and the Army Corps of Engineers authored a revised definition of WOTUS and promulgated a final rule. 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 challenges to this rule have resumed. In the meantime, securing CWA permits may be more challenging since the agencies in the states where a stay has been issued have less guidance to rely on to determine whether certain features are considered WOTUS. To the extent the implementation of the final rule, results of the litigation, or any further action expands the scope of jurisdiction, it may impose greater compliance costs or operational requirements on our coal mining operations.

Bellaire is treating mine water drainage from coal refuse piles associated with former underground coal mines in Ohio and Pennsylvania and is treating mine water from a former underground coal mine in Pennsylvania. Bellaire anticipates that it will need to continue these activities indefinitely. In 2004, Bellaire was notified by the Pennsylvania Department of Environmental Protection that it was required to establish a mine water treatment trust to serve as a long-term funding mechanism related to this obligation. See Note 7 and Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on Bellaire.

These federal and state requirements could require more costly water treatment and could materially adversely affect our business, financial condition and results of operations.

Resource Conservation and Recovery Act

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. The EPA also established alternative deadlines to cease receipt of waste to include new site-specific alternatives due to lack of disposal capacity with a deadline to initiate closure and a new site-specific alternative due to permanent cessation of coal-fired boilers with deadlines to complete closure.

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) and CCR Management Units (CCRMUs). In May 2024, the EPA published a final rule amending CCR regulations which ~~introduces~~introduced new requirements for the management of coal ash at active coal-fired power plants and inactive coal-fired power plants with a legacy surface impoundment. The regulations impose new requirements including groundwater monitoring, closure standards, post-closure care obligations, and potential remediation activities. During 2025, the EPA announced a number of interpretation and guidance changes to its CCR Rule, including its intention to reconsider the CCR Rule, which will require a new round of notice-and-comment rulemaking. No schedule for this rulemaking has yet been announced. We are currently unable to predict any specific changes or how such changes, if any, may impact our operations.

In compliance with these regulations, Falkirk's customer, the owner of the Coal Creek Station power plant, submitted a CCR Part B application to the EPA in 2020 asserting a unit complied with the CCR rules. In 2023, the EPA proposed to deny the owner’s application. The owner and other parties submitted additional information and comments supporting the owner’s position. The owner and the EPA continue to work through a path forward to provide a long-term solution. Additionally, the owner is taking operational steps to ensure there is no interruption to its disposal needs and no interruption of operations while working through the issue.

National Environmental Policy Act (NEPA)

The 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. Historically, this process may take several years to complete. In May 2025, the SCOTUS significantly narrowed the scope of environmental review required under NEPA, reinforcing that courts must give substantial deference to federal agencies. The SCOTUS iterated that NEPA is a procedural statute, not outcome-mandating. Furthermore, agencies are not required to analyze effects from separate, future or geographically distinct projects. Finally, agencies are permitted to limit NEPA analysis to impacts directly tied to the project and within their jurisdiction. The Council on Environmental Quality (CEQ) emphasized the need for agencies to streamline procedures and ensure that the NEPA process does not go on for too long in time or in volume. In January 2026, the CEQ published a final rule formally rescinding all NEPA implementation regulations and providing that CEQ will no longer issue government-wide NEPA regulations. This action moves all NEPA implementation to each individual federal agency and each individual federal agency must now revise its own NEPA procedures within one year, per CEQ direction. We are currently unable to predict any specific changes or how such changes, if any, may impact our operations.

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)

CERCLA and similar state laws create liabilities for the investigation and remediation of releases of hazardous substances into the environment and for damages to natural resources. We must also comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.

Endangered Species Act (ESA)

The ESA and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Some of our properties, projects or mineral interests may be located in areas that are or may be designated as habitats for endangered or threatened species, and previously unprotected species may later be designated as threatened or endangered in areas where we own property, projects or mineral interests. The ESA restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating limitations or restrictions or a temporary, seasonal or permanent ban on operations in affected areas. Similar protections are afforded to migratory birds under the Migratory Bird Treaty Act (MBTA). Compliance with ESA and MBTA requirements can significantly delay, limit, or even prevent the development of our properties, projects and mineral interests, and also result in increased costs.

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~~These~~Drilling ~~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 our mines. Any such closure of our mines could have a material adverse effect on our business, financial condition and results of operations.Production

InOur ~~compliance~~third-party ~~with~~lessees ~~these~~and ~~regulations,~~our ~~Falkirk's~~equity ~~customer,~~method ~~the~~investee ~~owner~~are ofsubject ~~the Coal Creek Station power plant, submitted a CCR Part B application~~ to ~~the~~various ~~EPA~~types inof ~~2020~~regulation ~~asserting~~at ~~a unit complied with~~ the ~~CCR rules. In the first quarter of 2023~~federal, ~~the~~state ~~EPA~~and ~~proposed~~local ~~to deny the owner’s application~~level. ~~The~~These ~~owner~~types ~~and~~of ~~other~~regulation ~~parties~~include ~~have~~requiring ~~submitted~~permits ~~additional~~for ~~information and comments supporting~~ the ~~owner’s~~drilling ~~position.~~of ~~If the EPA ultimately denies the owner’s application~~wells, adrilling ~~new~~bonds ~~liner may need to be installed or new waste management processes~~ and~~/or~~ ~~units~~generating ~~may~~reports ~~need~~concerning ~~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~~. ToThe ~~minimize any impact to operations~~states, ~~Coal~~and ~~Creek~~some ~~Station~~counties ~~continues to work with the EPA~~ and ~~is moving forward with plans to dry CCR materials produced by the plant~~municipalities, ~~reducing the need to utilize the lined area~~ in ~~question.~~which ~~Falkirk~~we ishave ~~the~~mineral ~~sole~~interests ~~supplier~~also ofregulate ~~lignite~~one 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~~more of the ~~power plants supplied by our mines could have a material adverse effect on our business, financial condition and results of operations.~~following:

~~National~~• the ~~Environmental~~location ~~Policy~~of ~~Act~~wells;

~~NEPA requires federal agencies to review~~ • the ~~environmental~~method ~~impacts~~ of ~~their~~drilling ~~decisions~~ and ~~issue~~casing ~~either an environmental~~wells;

~~assessment~~• the ortiming anof ~~environmental~~construction ~~impact~~or ~~statement.~~drilling ~~There~~activities, ~~are~~including ~~certain~~seasonal ~~actions~~wildlife ~~associated with surface coal mining that may trigger~~closures;

~~these~~• the ~~types~~rates of ~~assessments by federal agencies. When a NEPA action is required, we provide the required~~production;

~~information to~~ • the ~~appropriate~~surface ~~federal~~use ~~agency~~and torestoration ~~enable~~of itproperties toupon ~~complete~~which ~~the~~wells ~~required~~are ~~study. Historically, this process has been~~drilled;

~~lengthy and may take several years to complete. In January 2023,~~ • the ~~White~~plugging ~~House~~and ~~Council~~abandoning onof ~~Environmental~~wells; ~~Quality (CEQ)~~and

~~issued~~• notice ~~interim guidance that instructs federal agencies~~ to, ~~quantify GHG emissions~~ and ~~use~~consultation ~~the social cost of greenhouse gases to calculate a monetary metric associated~~ with, ~~the~~surface ~~proposed~~owners ~~actions’ climate effects. The NEPA~~ and ~~interim~~other ~~guidance~~third ~~could adversely affect our ability to secure necessary permits~~parties.

OnState ~~June~~laws 3,regulate ~~2023~~the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, ~~President~~forced ~~Biden~~pooling ~~signed~~or unitization may be implemented by third parties and may reduce our interest in the ~~Fiscal~~unitized ~~Responsibility~~properties. ~~Act~~In addition, state conservation laws establish maximum rates of ~~2023~~production ~~into~~from ~~law~~oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that the lessees of our mineral interests can produce from existing wells or limit the number of wells or the locations at which ~~included~~operators ~~certain~~can ~~provisions~~drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

~~collectively~~Federal, ~~known~~state asand local regulations provide detailed requirements for the ~~Builder~~abandonment ~~Act~~of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of the acreage underlying our mineral and royalty interests operate. The ~~Builder~~USACE ~~Act~~and ~~includes~~many ~~amendments~~other tostate ~~NEPA~~and ~~which~~local ~~codify~~authorities ~~past~~also ~~regulatory~~have ~~reforms~~regulations for plugging and abandonment, decommissioning and site restoration. Although the USACE does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

~~including~~Regulation ~~narrowing what qualifies as a major federal action, limiting the scope~~ of ~~NEPA~~Hydraulic ~~review to “reasonably foreseeable~~Fracturing

~~environmental~~The ~~effects,”~~operators ~~narrowing~~that ~~consideration~~produce oil and gas sometimes engage in hydraulic fracturing to stimulate production of ~~cumulative~~hydrocarbons ~~effects~~from tight formations, ~~directing~~including ~~agencies~~shales. The process involves the injection of water, sand and chemicals under pressure into formations to ~~only~~fracture ~~consider~~the ~~technically~~surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions.

~~economically~~Several ~~feasible~~states ~~reasonable~~where ~~alternatives~~we own interests in oil and ~~providing~~gas ~~page~~producing ~~limits~~properties, including Texas, have adopted regulations that could restrict or prohibit hydraulic fracturing in certain circumstances with regard to the use of fracturing fluids or require the disclosure of the composition of hydraulic-fracturing fluids. For example, the Texas Legislature previously adopted legislation requiring oil and ~~timelines~~gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. The Texas Railroad Commission subsequently adopted rules and regulations implementing this legislation that apply to all wells for ~~environmental~~which ~~impact~~the ~~statements~~Railroad Commission issues an initial drilling permit. This law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the Occupational Safety and Health Act for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Further, in May 2013, the Texas Railroad Commission issued a well integrity rule, which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as: (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later; and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. These existing or any new legal requirements regulating or prohibiting the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, will likely result in added costs to comply and affect the operators’ rate of production.

~~environmental~~In ~~assessments~~some instances, the operation of underground injection wells has been alleged to cause earthquakes. InSuch ~~April~~issues ~~2024,~~have sometimes led to orders prohibiting continued injection or the ~~CEQ~~suspension ~~finalized~~of drilling in certain wells identified as possible sources of seismic activity. For example, Oklahoma, New Mexico and Texas have imposed certain limits on the ~~revised~~permitting ~~NEPA~~or ~~rules~~operation of disposal wells in areas with increased instances of induced seismic events. Future orders or regulations addressing concerns about seismic activity from well injection could affect operations on the acreage underlying our mineral interests or our equity method investment.

On February 16, 2025, CEQ issued a notice that it intends to rescind all CEQ NEPA implementing regulations. These actions have raised significant questions regarding how CEQ’s NEPA regulations and agency-specific NEPA procedures will be interpreted and enforced going forward. We are unable to predict what impact the new CEQ guidance will have on our ability to obtain governmental permits.

Federal Coal Leasing

We enter into leases of Federally owned coal for a small portion of the coal mined at certain of our North Dakota mines. In July 2024, the Department of Interior’s Bureau of Land Management (BLM) published its North Dakota Proposed Resource Management Plan (RMP), which provided that no Federal coal which lies more than four miles away from a currently existing surface coal mining permit will be available for future leasing in North Dakota. In September 2024, the Company, along with other stakeholders, including the Governor of North Dakota, filed protests against the RMP. The BLM denied the protests and published the final RMP in January 2025. The State of North Dakota filed a challenge to the RMP in the United States District Court for the District of North Dakota on February 25, 2025. We are currently evaluating a similar challenge. If any such challenges are not successful, we may be required to alter our mine plans to avoid areas of Federal coal in the future.

Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar assets.

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~~The~~There ~~availability~~has been increasing public controversy regarding hydraulic fracturing with regard to water, ~~terms~~including ~~and~~the ~~cost~~use of ~~transportation~~a ~~significantly~~significant ~~affect~~amount ~~sales~~ of ~~oil~~water, impacts on drinking water and ~~natural~~the ~~gas.~~potential ~~The~~for ~~interstate~~impacts ~~transportation~~to ofsurface ~~oil~~water and ~~natural~~groundwater. ~~gas~~The ~~and~~inability of the ~~sale~~operators orof ~~resale~~the ofacreage ~~natural~~underlying ~~gas~~our ismineral ~~subject~~interests to ~~federal~~locate ~~regulation,~~sufficient ~~including~~amounts ~~regulation~~of water or dispose of ~~the~~or ~~terms,~~recycle ~~conditions~~water used in their drilling and ~~rates~~production ~~for~~operations ~~interstate~~could ~~transportation~~adversely impact their operations. Moreover, ~~storage~~a number of lawsuits and ~~various~~enforcement ~~other~~actions ~~matters,~~have ~~primarily~~been byinitiated across the ~~Federal~~country ~~Energy~~implicating ~~Regulatory~~hydraulic ~~Commission~~fracturing ~~(FERC)~~practices. ~~Federal~~If ~~and~~hydraulic ~~state~~fracturing ~~regulations~~is ~~govern~~further regulated at the ~~price~~federal ~~and~~or ~~terms~~state ~~for~~level, ~~access~~fracturing activities could become subject to ~~oil~~additional permitting and ~~natural~~financial ~~gas~~assurance ~~pipeline~~requirements, ~~transportation.~~more ~~FERC’s~~stringent ~~regulations~~construction ~~for~~specifications, ~~interstate~~increased ~~oil~~monitoring, reporting and ~~natural~~recordkeeping ~~gas~~obligations, ~~transmission~~plugging inand ~~some~~abandonment ~~circumstances~~requirements ~~may~~and also ~~affect~~to ~~the~~attendant ~~intrastate~~permitting ~~transportation~~delays ofand ~~oil~~potential ~~and~~increases ~~natural~~in ~~gas~~costs.

~~Although~~In ~~oil~~addition ~~and~~to ~~natural~~state ~~gas~~laws, ~~prices~~local ~~are~~land ~~currently~~use ~~unregulated~~restrictions, ~~Congress~~such ~~historically~~as ~~has~~city ~~been~~ordinances, ~~active~~may inrestrict or prohibit the ~~area~~performance of ~~oil~~well ~~and~~drilling ~~natural~~in ~~gas~~general ~~regulation~~or hydraulic fracturing in particular. We cannot predict ~~whether~~what ~~new~~additional ~~legislation~~state toor ~~regulate~~local ~~oil~~requirements ~~and~~may ~~natural~~be ~~gas~~imposed ~~might~~in bethe ~~proposed,~~future ~~what~~on ~~proposals,~~oil ifand ~~any,~~gas ~~might~~operations bein ~~enacted~~the bystates ~~Congress~~where orwe own interests. In the ~~various~~event state, ~~legislatures~~local, ~~and~~or ~~what~~municipal ~~effect,~~legal ifrestrictions ~~any~~are adopted in areas where operators that produce our oil and gas conduct operations, ~~the~~those ~~proposals~~operators ~~might~~may ~~have~~incur onsubstantial ~~the~~costs ~~Minerals~~to ~~Management~~comply ~~segment.~~with ~~Sales~~these ofrequirements, ~~crude~~experience ~~oil~~delays, ~~condensate~~or ~~and~~curtailment, ~~natural~~in ~~gas~~the ~~liquids~~pursuit ~~(NGLs)~~of ~~are~~exploration, ~~not~~development, ~~currently~~or ~~regulated~~production activities and ~~are~~perhaps ~~made~~even atbe ~~market~~precluded ~~prices~~from the drilling of wells.

~~Environmental~~Natural ~~Matters~~Gas and Oil Sales and Transportation

~~Oil~~The ~~and natural gas exploration~~availability, ~~development~~terms and ~~production~~cost ~~operations are subject to stringent laws and regulations governing the discharge~~ of ~~materials~~transportation ~~into~~significantly the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our mineral interests, which could materially adversely affect ~~the~~sales Minerals Management segment. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of aoil ~~permit before drilling commences, restrict the types, quantities~~ and ~~concentrations~~natural of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operationsgas. The ~~strict,~~interstate ~~joint~~transportation ~~and several liability nature~~ of such laws and regulations could impose liability upon the operators on our mineral interests, regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

~~In December 2023, EPA finalized a rule that will require~~ oil and natural gas ~~producers to reduce methane~~ and ~~other~~the ~~air~~sale ~~pollutants~~or ~~from~~resale ~~existing sources. Oil and gas companies will be required to phase out routine flaring~~ of natural gas ~~and~~is ~~install~~subject ~~methane~~to ~~leak~~federal ~~detection equipment. Changes in environmental laws and regulations occur frequently~~regulation, ~~and~~including ~~any~~regulation ~~changes~~of ~~that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect~~ the ~~Minerals Management segment.~~terms,

Inconditions ~~May 2024, the EPA finalized a rule containing revisions~~ and ~~additions~~rates ~~to the New Source Performance Standards (NSPS) program rules (the Final Methane Rule). The Final Methane Rule formally reinstates emission limitations on methane, a GHG emission,~~ for ~~existing~~interstate ~~and modified facilities in the oil and gas sector. Specifically~~transportation, ~~the~~storage ~~Final Methane Rule requires states to implement plans that meet or exceed federally established emission reduction guidelines for oil~~ and ~~natural~~various ~~gas~~other ~~facilities. Several states and industry groups have filed suit before the D.C. Circuit challenging the Final Methane Rule. On October 4~~matters, ~~2024,~~primarily ~~the SCOTUS denied applications for an immediate stay of the Final Methane Rule pending review~~ by the ~~D.C.~~Federal ~~Circuit~~Energy Court of Appeals. Though the final outcome is uncertain, the rule establishes standards of performance for sources that commence construction, modification or reconstruction after March 8, 2024, and establishes emissions guidelines that will inform state plans to establish standards for existing sources. The Final Methane Rule could have a significant impact on the upstream and midstream oil and gas sectors.Regulatory

InCommission ~~November 2024, the EPA announced a final rule to reduce methane emissions from the oil and gas sector. The rule requires payment of a Waste Emissions Charge~~ (~~WEC~~FERC). onFederal ~~waste emissions of methane from certain oil~~ and ~~gas~~state ~~facilities.~~regulations ~~The~~govern ~~Inflation Reduction Act-mandated fee would be triggered when companies report more than 25 metric tons of carbon dioxide equivalent per year to~~ the ~~EPA's~~price ~~Greenhouse Gas Reporting Program. The fee begins at $900 per metric ton of methane exceeding that threshold in 2024~~ and ~~increases~~terms ~~over time. A petition~~ for ~~review~~access ~~was~~to ~~filed in January 2025 by a coalition of Texas-led states and other industry groups. The fee could have a significant impact on the upstream and midstream~~ oil and natural gas ~~sectors.~~pipeline

~~Drilling~~transportation. FERC’s regulations for interstate oil and ~~Production~~natural gas transmission in some circumstances may also affect the

~~The~~intrastate ~~operations~~transportation of ~~the~~oil ~~Minerals Management segment’s third-party lessees~~ and ~~our~~natural ~~equity method investee are subject to various types of regulation at the federal, state and local level~~gas. ~~These types of regulation include requiring permits for the drilling of~~

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural

gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, or what proposals, if any, might be enacted by Congress or the various state legislatures.

Other Laws and Regulations

On July 4, 2025, the One Big Beautiful Bill Act (OBBBA) was signed into law. The OBBBA includes changes to U.S. tax law including provisions for bonus depreciation, current expensing of research expenditures and changes to the interest deductibility threshold. The changes resulting from the tax provisions in OBBBA are not expected to have a material impact on our results of operations.

The OBBBA includes substantial changes to U.S. solar energy tax policy which could have a material impact on the

projects being developed by ReGen Resources. Current projects in development include solar arrays, solar-gas hybrid projects, thermal generation and carbon capture primarily on reclaimed mining properties in Louisiana, Mississippi, Ohio, Pennsylvania and Texas. ReGen develops energy infrastructure projects directly as well as through joint ventures. Our investments in solar projects are dependent, in part, on federal tax incentives to preserve economic value. We believe all current solar projects have been safe harbored in order to preserve tax credit eligibility. We have approximately $8.4 million of capitalized assets associated with our solar projects. We have incurred, and will continue to incur, costs in connection with these projects and the results of operations and/or return on investment could be lower than anticipated.

The United States has enacted and proposed to enact significant new tariffs. Additionally, President Trump has directed

various federal agencies to further evaluate key aspects of U.S. trade policy and there has been ongoing discussion and

commentary regarding potential significant changes to U.S. trade policies, treaties, and tariffs. While in February 2026 the SCOTUS limited the ability of the President of the United States to implement certain tariffs without the express authorization of Congress, there continues to exist significant uncertainty about the future relationship between the U.S. and other countries with respect to such trade policies, treaties, and tariffs.These developments, or the perception that any such policies, treaties, or tariffs could be implemented, could restrict our access to suppliers and increase the cost of equipment and supplies imported into the U.S.

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wells, drilling bonds and generating reports concerning operations. The states, and some counties and municipalities, in which we have mineral interests also regulate one or more of the following:

•the location of wells;

•the method of drilling and casing wells;

•the timing of construction or drilling activities, including seasonal wildlife closures;

•the rates of production;

•the surface use and restoration of properties upon which wells are drilled;

•the plugging and abandoning of wells; and

•notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that the lessees of our mineral interests can produce from existing wells or limit the number of wells or the locations at which operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but the effect of any future regulations could have a material effect on the Minerals Management segment. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our mineral interests, negatively affect the economics of production from these wells or limit the number of locations operators can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of the acreage underlying our mineral and royalty interests operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

On January 20, 2025, President Trump issued several executive orders that prioritized energy security, exploration and production on federal lands and processing of Liquefied Natural Gas export applications. Implementation of these executive orders could positively impact domestic drilling and production of oil and natural gas.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The CWA regulates the underground injection of substances through the Underground Injection Control (UIC) program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions.

Several states, including Texas, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature previously adopted legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission subsequently adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit. This law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the Occupational Safety and Health Act for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Further, in May 2013, the Texas Railroad Commission issued a well integrity rule, which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as: (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later; and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing

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practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative or regulatory changes could cause operators of the operation on the acreage underlying our mineral interests, including those held by our equity method investee, to incur substantial compliance costs, and compliance or the consequences of any failure to comply by operators could have a material adverse effect on the Minerals Management segment.

In addition, hydraulic fracturing operations require the use of a significant amount of water, and the inability of the operators of the acreage underlying our mineral interests to locate sufficient amounts of water or dispose of or recycle water used in their drilling and production operations could adversely impact their operations. Moreover, new environmental initiatives and regulations could include restrictions on the ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the development or production of natural gas.

In some instances, the operation of underground injection wells has been alleged to cause earthquakes. Such issues have sometimes led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity. Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. Future orders or regulations addressing concerns about seismic activity from well injection could affect operations on the acreage underlying our mineral interests or our equity method investment.

Endangered Species Act

The Endangered Species Act (ESA) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Pursuant to a settlement with environmental groups, the U.S. Fish and Wildlife Service (USFWS) was required to determine whether over 250 species required listing as threatened or endangered under the ESA. USFWS has not yet completed its review, but the potential remains for new species to be listed under the ESA. Some of our properties or mineral interests may be located in areas that are or may be designated as habitats for endangered or threatened species, and previously unprotected species may later be designated as threatened or endangered in areas where we hold interests. For example, recently, there have been renewed calls to review protections currently in place for the Dunes Sagebrush Lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA. Likewise, there have been calls to review protections in place for the Greater Sage Grouse, which can be found across a large swath of the northwestern United States in oil and gas producing states. The listing of either of these species, or any others, in areas where we hold mineral interests could cause lessees to incur increased costs arising from species protection measures, delay the completion of exploration and production activities, and/or result in limitations on operating activities that could have an adverse impact the Minerals Management segment.

Natural Gas Sales and Transportation

Historically, federal legislation and regulatory controls have affected the price and marketing of natural gas. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in first sales. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which operators may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that operators produce, as well as the revenues operators receive for sales of natural gas and release of natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on natural gas-related activities.

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Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in-state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase operators’ costs of transporting gas to point-of-sale locations.

Oil Sales and Transportation

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by portioning provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to our operators to the same extent as they are to our competitors.

State Regulation

States regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot be certain that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from wells and to limit the number of drilled wells or locations of our third-party lessee operators or of our equity method investment.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on our results of operations or financial condition.

Comprehensive Environmental Response, Compensation and Liability Act

From time to time, we have been the subject of administrative proceedings, litigation and investigations relating to environmental matters. The extent of the liability and the cost of complying with environmental laws cannot be predicted with certainty due to many factors, including the lack of specific information available with respect to many sites, the potential for new or changed laws and regulations, the development of new remediation technologies and the uncertainty regarding the timing of work with respect to particular sites. As a result, we may incur material liabilities or costs related to environmental matters in the future, and such environmental liabilities or costs could materially and adversely affect our results of operations and financial condition. In addition, there can be no assurance that changes in laws or regulations would not affect the manner in which we are required to conduct our operations.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The following tables set forth as of March 1, ~~2025~~2026 the name, age, current position and principal occupation and employment during the past five years of our executive officers. There exists no arrangement or understanding between any executive officer and any other person pursuant to which such executive officer was selected.

EXECUTIVE OFFICERS OF THE COMPANY

Name

Age

Current Position

J.C. Butler, Jr.

6465

President and Chief Executive Officer of NACCO and President and Chief Executive Officer of NACCO Natural Resources Corporation (NNRC) (from prior to ~~2019~~2020)

Elizabeth I. Loveman

5556

Senior Vice President and Controller and Principal Financial Officer (from prior to ~~2019~~2020)

John D. Neumann

4950

Senior Vice President, General Counsel and Secretary of NACCO, Senior Vice President, General Counsel and Secretary of NNRC (from prior to ~~2019~~2020)

Thomas A. Maxwell

4748

Senior Vice President - ~~Financial~~Finance ~~Planning~~ and ~~Analysis and~~ Treasurer (from prior to ~~2019~~2020)

PRINCIPAL OFFICERS OF THE COMPANY’S SUBSIDIARIES

Name

Age

Current Position

J.C. Butler, Jr.

6465

President and Chief Executive Officer of NACCO and President and Chief Executive Officer of NNRC (from prior to ~~2019~~2020)

Carroll L. Dewing

6869

Senior Vice President and Chief Operating Officer of NNRC (from prior to ~~2019~~2020)

John D. Neumann

4950

Senior Vice President, General Counsel and Secretary of NACCO, Senior Vice President, General Counsel and Secretary of NNRC (from prior to ~~2019~~2020)

J. Patrick Sullivan, Jr.

6667

Senior Vice President and Chief Financial Officer of NNRC (from prior to ~~2019~~2020)

Item 1A. RISK FACTORS

We operate in a rapidly changing environment that involves a number of risks. The following discussion highlights some of these risks and others are discussed elsewhere in this report. These and other risks could materially and adversely affect our business, financial condition, operating results or cash flows. The following risk factors are not an exhaustive list of the risks associated with our business. New factors may emerge or changes to these risks could occur that could materially affect our business. See Item 1. Business — Government Regulation and Environmental Matters on page 9 in this Form 10-K for discussion of regulations that could materially adversely affect our businesses.

Risks related to the Utility Coal Mining segment

MLMC is subject to risks associated with our capital investment, operating and equipment costs, changes in customer demand and inflationary adjustments.

Profitability at MLMC is affected by customer demand for coal, changes in the contractually determined sales price and actual costs incurred. The MLMC contract is the only coal supply contract in which we are responsible for all operating costs, capital requirements and final mine reclamation. As such, increased costs or decreased revenues could materially reduce our profitability. As a significant portion of MLMC’s costs are fixed, reduction in dispatch and/or reduced mechanical availability of the Red Hills Power Plant can and historically has materially reduced operating results at MLMC. Conversely, periods of higher dispatch can improve results. In February 2026, MLMC received notice from its customer that the Red Hills Power Plant experienced an unplanned outage, which is expected to lead to reduced demand and an anticipated operating loss for MLMC during 2026.

Any reduction in customer demand at MLMC, including fluctuations in demand due to planned and unplanned outages at the customer's Red Hills Power Plant, unanticipated weather conditions, economic conditions, governmental regulations and inflationary adjustments could have a material adverse effect on MLMC's financial condition, results of operations and cash flows.

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Termination of or default under long-term mining contracts could adversely affect our business, financial condition, results of operation and cash flows.

Substantially all of the Utility Coal Mining segment's profits are derived from long-term mining contracts. Although we have long-term contracts, ~~numerous~~any regulatory authorities, along with well-funded political and environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation. Any customer's premature facility closure or contract default could have a material adverse effect on our business, financial condition and results of operations.

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

The coal mining industry and the electric generation industry are subject to extensive regulation by federal, state and local authorities on matters concerning the health and safety of employees, land use, stream and wetland protection, permit and licensing requirements, air and water quality standards, plant and wildlife protection, reclamation and restoration of mining properties after mining, the discharge of GHGs and other materials into the environment, ~~surface subsidence from underground mining~~ and the effects that mining has on groundwater quality and availability. Legislation mandating certain benefits for current and retired coal miners also affects the industry. Mining operations require numerous governmental and regulatory permits and approvals. We are required to prepare and present to federal, state or local authorities data pertaining to the impact the production and combustion of coal may have upon the environment. The public, including non-governmental organizations, opposition groups and individuals, have statutory rights to comment upon and submit objections to requested permits and approvals and to legally challenge certain permits subsequent to their issuance. Compliance with these requirements is costly and time-consuming and may delay commencement or continuation of development or production. New legislation and/or regulations and orders may materially adversely affect our mining operations, cost structure or customers. All of these factors could significantly reduce our profitability.

18The potential impact of future laws, regulations or other policies or circumstances will depend upon the degree to which any such laws, regulations or other policies or circumstances require electricity generators to diminish their reliance on coal as a fuel source. Complicating these matters further, over the last several decades, U.S. Administrations have increasingly relied on regulations and executive orders to implement environmental policies and objectives in the absence of Congressional agreement regarding new legislation. This condition, which creates instability and unpredictability of environmental regulations, seems likely to persist and could increase due to apparent polarization between the two main political parties. As a result, we and/or our customers, often must comply with and otherwise adapt to environmental regulations without assurance of their continued effect. We and/or our customers often do not have the ability to anticipate, or prepare in advance for, changes in regulatory approaches that may be implemented following a change in Administration.

~~Table~~In view of ~~Contents~~the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict the impact that any such laws, regulations or other policies may have on our business, financial condition and results of operations. However, such impacts could have a material adverse effect on our business, financial condition and results of operations.

approvals and to legally challenge certain permits subsequent to their issuance. Compliance with these requirements is costly and time-consuming and may delay commencement or continuation of development or production. New legislation and/or regulations and orders may materially adversely affect our mining operations, cost structure or customers. All of these factors could significantly reduce our profitability.

Congress has considered climate change legislation aimed at reducing GHG emissions, particularly from coal combustion by power plants. Enactment of laws and passage of regulations regarding GHG emissions at the federal or state level, or other actions to limit carbon dioxide emissions, such as opposition by environmental groups of coal-fired power plants, could result in electric generators switching from coal to other fuel sources or premature facility closures.

Congress continues to consider a variety of proposals to reduce GHG emissions from the combustion of coal and other fuels. These proposals include emission taxes, emission reductions, including carbon tax and cap-and-trade programs, and mandates or incentives to generate electricity by using renewable energy sources, such as wind or solar power. Some states have established programs to reduce GHG emissions. Further, certain governmental agencies provide grants or other financial incentives to entities developing or selling alternative energy sources with lower levels of GHG emissions, which may lead to more competition from those entities.

The potential impact on us of future laws, regulations or other policies or circumstances will depend upon the degree to which any such laws, regulations or other policies or circumstances require electricity generators to diminish their reliance on coal as a fuel source. Complicating these matters further, over the last several decades, U.S. Administrations have increasingly relied on regulations and executive orders to implement environmental policies and objectives in the absence of Congressional agreement regarding new legislation. This condition, which creates instability and unpredictability of environmental regulations, seems likely to persist and could increase due to apparent polarization between the two main political parties. As a result, we and/or our customers, often must comply with and otherwise adapt to environmental regulations without assurance of their continued effect. We and/or our customers often do not have the ability to anticipate, or prepare in advance for, changes in regulatory approaches that may be implemented following a change in Administration. The SCOTUS’s recent decision in Loper Bright Enterprises v. Raimondo overturned the SCOTUS’s longstanding deferral to the applicable agency’s interpretation of ambiguous federal laws. We are unable to predict whether, or to what extent, this decision will alter the outcome of judicial reviews of current or future regulations. We do not know whether risks related to current and future regulations affecting us will be significantly mitigated by the decision in Loper Bright.

In view of the significant uncertainty surrounding each of these factors, it is not possible for us to predict reasonably the impact that any such laws, regulations or other policies may have on our business, financial condition and results of operations. However, such impacts could have a material adverse effect on our business, financial condition and results of operations.

See Item 1. Business — Government Regulation on page 9 in this Form 10-K for discussion of regulations that could materially adversely affect the Coal Mining segment.

The loss of, or significant reduction in, purchases by NACCO's coal customers could adversely affect our business, financial condition, results of operation and cash flows.

Earnings from the Utility Coal Mining segment's customers may fluctuate from time to time based on numerous factors, including market conditions and the realignment of customers' power generation portfolios that reduce the electric power generated from coal, which may be outside of our control. If any of the Utility Coal Mining segment's customers experience declining demand due to market, economic, regulatory or competitive conditions, it could have an adverse effect on our profitability, cash flows and financial position. In addition, if any customers were to significantly reduce or eliminate their purchases of coal from us or if we are unable to renew expiring long-term sales agreements with existing customers or enter into new supply agreements, our business, financial condition, results of operations and cash flows could be adversely affected. ~~See Item 1. Business — Business Developments on page 2 in this Form 10-K for further discussion.~~

~~MLMC~~The isUtility ~~subject~~Coal toMining ~~risks~~segment's ~~associated~~Unconsolidated ~~with~~Subsidiaries ~~our~~are ~~capital~~subject ~~investment,~~to ~~operating~~risks ~~and~~created ~~equipment~~by ~~costs, growing use of alternative generation that competes with coal-fired generation,~~ changes in customer demand and inflationary adjustments.

The ~~profitability~~contracts with the Unconsolidated Subsidiaries' customers are primarily based on a management fee approach, whereby compensation includes reimbursement of ~~MLMC~~all isoperating ~~subject~~costs, toplus a fee based on the ~~risk~~amount of ~~loss~~coal ofdelivered. ~~investment~~The fees earned adjust over time in ~~this~~line ~~operation~~with various indices which reflect general U.S. inflation rates. During the production stage, ~~increases~~the inUnconsolidated Subsidiaries' customers pay us our agreed upon fee only for the ~~cost~~coal ofdelivered ~~mining~~to them for consumption or use. As a result, ~~changes~~reduced incoal usage by customers for any reason, including, but not limited to, reduced availability of the customer’s power plant, dispatch of power generated by other energy sources, fluctuations in demand due to unanticipated weather conditions, ~~adverse~~planned ~~mining~~and unplanned outages at the Utility Coal Mining segment's customers' facilities, economic conditions and ~~growing~~governmental ~~competition~~regulations ~~from~~could ~~alternative~~have ~~power~~a ~~generation~~material ~~that~~adverse ~~competes~~effect ~~with~~on ~~coal-fired~~our ~~generation~~results of operations. AtBecause ~~MLMC~~of the contractual price formulas for the management fees at these Unconsolidated Subsidiaries, the ~~costs~~profitability of ~~mining~~these operations ~~are~~is ~~not~~also ~~reimbursed~~subject byto ~~MLMC's~~fluctuations ~~customer.~~in Asinflationary ~~such,~~adjustments ~~increased~~(or ~~costs~~lack orthereof) ~~decreased~~that ~~revenues~~can impact the agreed upon management fees. These factors could materially reduce our profitability.

Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred. MLMC sells lignite at contractually agreed upon prices which are subject to changes in the level of established 16

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indices over time. All production costs at MLMC are capitalized into inventory and recognized in cost of sales as tons are delivered. In periods of limited or no deliveries, MLMC may be required to reduce inventory carrying value using the lower of cost and net realizable value approach, which could adversely affect MLMC’s results of operations.

Diesel fuel is heavily weighted among the indices used to determine the coal sales price. The diesel fuel-related component of the coal sales price is based on average price changes over time whereas the impact on actual costs from changes in diesel fuel prices is more immediate; therefore, fluctuations in diesel fuel prices can result in significant fluctuations in earnings at MLMC.

Any reduction in customer demand at MLMC, including, but not limited to, reduced availability of the customer’s power plant, dispatch of power generated by other energy sources, fluctuations in demand due to unanticipated weather conditions, planned and unplanned outages at the customer's Red Hills Power Plant, economic conditions, governmental regulations and inflationary adjustments could have a material adverse effect on MLMC's financial condition, results of operations and cash flows.

The Coal Mining segment's Unconsolidated Subsidiaries are subject to risks created by changes in customer demand and inflationary adjustments.

The contracts with the Unconsolidated Subsidiaries' customers are primarily based on a management fee approach, whereby compensation includes reimbursement of all operating costs, plus a fee based on the amount of coal delivered. The fees earned adjust over time in line with various indices which reflect general U.S. inflation rates. During the production stage, the Unconsolidated Subsidiaries' customers pay us our agreed upon fee only for the coal delivered to them for consumption or use. As a result, reduced coal usage by customers for any reason, including, but not limited to, reduced availability of the customer’s power plant, dispatch of power generated by other energy sources, fluctuations in demand due to unanticipated weather conditions, planned and unplanned outages at the Coal Mining segment's customers' facilities, economic conditions and governmental regulations could have a material adverse effect on our results of operations. Because of the contractual price formulas for the management fees at these Unconsolidated Subsidiaries, the profitability of these operations is also subject to fluctuations in inflationary adjustments (or lack thereof) that can impact the agreed upon management fees. These factors could materially reduce our profitability.

Changes in coal consumption patterns of U.S. electric power generators could adversely affect our profitability.

The amount of coal consumed by the electric power generation industry is affected by general economic conditions; overall demand for electricity; availability of transmission; competition from alternative fuel sources for power generation, such as natural gas, nuclear, hydroelectric, wind and solar power, and the location, availability, quality and price of those alternative fuel sources; and environmental and other governmental regulations,. ~~including~~Changes ~~those~~in ~~impacting~~the utility industry that affect NACCO's customers could also adversely affect us. Any of these risks could result in a decrease in coal~~-fired~~ ~~power~~consumption ~~plants;~~by our customers and ~~energy~~could ~~conservation~~have ~~efforts~~a material adverse effect on our business, financial condition and ~~related~~results ~~governmental~~of ~~policies~~operations.

Changes in the utility industry that affect NACCO's customers could also adversely affect us. The increased availability of renewable energy sources has contributed to a reduction in demand for coal-fired electric power generation. Competition from natural gas-fired plants that are relatively more efficient, less expensive to construct and less difficult to permit than coal-fired plants have the most potential to continue to displace a significant amount of coal-fired electric power generation. Federal and state mandates for increased use of electricity derived from renewable energy sources have also adversely affected demand for coal-fired electric power generation. Such mandates make alternative fuel sources more competitive with coal-fired electric power generation.

Any of these risks could result in a decrease in coal consumption by our customers and could have a material adverse effect on our business, financial condition and results of operations.

We are subject to burdensome federal and state mining regulations and the assumptions underlying our reclamation and mine closure obligations could be materially inaccurate.

Federal and state statutes require us to restore mine property in accordance with specified standards and an approved reclamation plan, and require that we obtain and periodically renew permits for mining operations. Regulations require us to incur the cost of reclaiming current mine disturbance at operations where we hold the mining permit. Estimates of our total reclamation and mine closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. While management regularly reviews the estimated reclamation liabilities and believes that appropriate accruals have been recorded for all expected reclamation and other costs associated with closed mines, the estimate can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Such changes could have a material adverse effect on our business and could significantly reduce our profitability.

20The Utility Coal Mining segment's customers' operations require significant capital expenditures.

~~Table~~Maintaining power plants requires significant capital expenditures. Any delay or reduction in making capital expenditures to maintain or upgrade coal-fired power plants by the Utility Coal Mining segment's customers, principally electric utilities, could result in an increase in outage days and a corresponding decrease in coal consumption. The Red Hills Power Plant operated at below full baseload capacity and experienced periods of ~~Contents~~reduced mechanical availability during 2024 and 2025. A decrease in coal consumption could have a material adverse effect on the Utility Coal Mining segment's financial condition, results of operations and cash flows.

The Coal Mining segment's customers' operations require significant capital expenditures.

Maintaining and installing environmental controls on power plants requires significant capital expenditures. Any delay or reduction in making capital expenditures to maintain or upgrade coal-fired power plants by the Coal Mining segment's customers, principally electric utilities, could result in an increase in outage days and a corresponding decrease in coal consumption. A decrease in coal consumption could have a material adverse effect on the Coal Mining segment's financial condition, results of operations and cash flows.

We face numerous uncertainties in estimating economically recoverable reserves and resources, and inaccuracies in estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.

Information concerning our mining operations in Item 2 - Properties on page 2925 has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K. A mineral is economically recoverable when the price at which it can be sold exceeds the costs and expenses of mining, processing and selling the mineral. Forecasts of NACCO's future performance are based on, among other things, estimates of mineral reserves and resources. Mineral reserve and resource estimates of the remaining tons of coal at MLMC are based on many factors, including engineering, economic and geological data assembled and analyzed by internal staff, which includes various engineers and geologists, the area and volume covered by mining rights, assumptions regarding extraction rates and duration of mining operations, and the quality of in-place reserves and resources. The reserve and resource estimates as to both quantity and quality are updated from time to time to reflect, among other matters, production of minerals, new mining or other data received.

There are numerous uncertainties inherent in estimating quantities and qualities of minerals and costs to mine recoverable reserves and resources, including many factors beyond our control. While we believe that our mineral reserve and resource estimates are developed using well-established practices and with appropriate controls, mineral reserve and mineral resource estimation is an imprecise and subjective process. Estimates of mineral reserves and resources depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:

•Geologic and mining conditions, including our ability to access certain mineral deposits as a result of the nature of the geologic formations of coal deposits or other factors, which may not be fully identified by available exploration data and may differ from past experience;

•Demand for our minerals;

•Contractual arrangements, operating costs and capital expenditures;

•Development and reclamation costs;

•Mining technology and processing improvements;

•The effects of regulation by governmental agencies, including volatility in the political, legal and regulatory environments due to the U.S. presidential administration;

•The ability to obtain, maintain and renew all required permits;

•Employee health and safety; and

•Our ability to convert all or any part of mineral resources to economically extractable mineral reserves.

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As a result, actual tonnage recovered, estimated revenues, expenditures and cash flows with respect to reserves and resources may vary materially from estimates. Thus, these estimates may not accurately reflect our actual reserves and resources. Any material inaccuracy in estimates related to our reserves or resources could result in lower than expected revenues, higher than expected costs or decreased profitability and changes in future cash flow, which could materially and adversely affect our business, results of operations, financial position and cash flows. Additionally, reserve and resource estimates may be adversely affected in the future by interpretations of, or changes to, the SEC’s property disclosure requirements for mining companies.

A defect in title or the loss of a leasehold interest in certain property could limit our ability to mine coal reserves or result in significant unanticipated costs.

We conduct a significant part of our coal mining operations on leased properties. A title defect or the loss of a lease could adversely affect the ability to mine the associated coal reserves. We may not verify title to leased properties or associated coal reserves until we are committed to developing those properties or coal reserves. We may not commit to develop property or coal reserves until we have obtained necessary permits and completed exploration. As such, the title to property that we intend to lease or mine may contain defects prohibiting the ability to conduct mining operations. Similarly, leasehold interests may be subject to superior property rights of third parties. In order to conduct mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, some leases require us to produce a minimum quantity of coal and/or pay minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest to terminate.

21Risks related to the Contract Mining segment

~~Table~~We ofhave ~~Contents~~experienced growth in our Contract Mining business in recent periods and we may not be able to sustain growth or manage future growth effectively.

~~Risks~~We ~~related~~have expanded our overall Contract Mining business, operations and headcount in recent periods. The Contract Mining segment's operating expenses may increase as we continue to scale the ~~NAMining~~Contract ~~segment~~Mining business. We must effectively integrate, develop and motivate employees, while integrating new equipment and customers in an efficient and effective manner. We anticipate that we will continue to incur costs and capital expenditures associated with future growth prior to realizing the full measure of anticipated long-term benefits, and the return on these investments may be lower, may develop more slowly than expected or may never be realized. If we are unable to manage this growth and the associated expenses effectively, we may not be able to take advantage of market opportunities or remain competitive. We may also fail to execute on our business plan or respond to competitive pressures, any of which could adversely affect the Contract Mining business, operating results and financial condition.

WeOur ~~have~~Contract ~~experienced~~Mining ~~growth in our NAMining~~ business infaces ~~recent~~competition ~~periods~~from ~~and~~customers wethat ~~may~~choose ~~not be able~~ to ~~sustain~~self-perform ~~growth~~mining oroperations ~~manage~~and ~~future~~from ~~growth~~other ~~effectively~~mining companies.

We ~~have~~face ~~expanded~~competition ~~our~~from ~~overall~~existing ~~NAMining~~and ~~business,~~prospective ~~operations~~customers ~~and~~that ~~headcount~~are incapable ~~recent~~of ~~periods.~~performing, ~~NAMining’s~~or ~~operating~~engaging ~~expenses~~other ~~may~~companies ~~continue~~ to ~~increase~~perform ~~as we scale~~ the ~~NAMining~~services ~~business~~we provide. We ~~must~~cannot ~~effectively~~be ~~integrate,~~certain ~~develop~~that ~~and~~our ~~motivate~~existing ~~employees, while integrating new equipment and~~ customers ~~in an efficient and effective manner. We anticipate that it~~ will continue to ~~incur~~outsource ~~costs and capital expenditures associated with future growth prior to realizing the full measure of anticipated long-term benefits, and the return on~~ these ~~investments~~services ~~may be lower, may develop more slowly than expected or may never be realized. If we are unable~~ to ~~manage~~us ~~this~~in ~~growth and~~ the ~~associated expenses effectively~~future, ~~we may not be able to take advantage of market opportunities or remain competitive. We may also fail to execute on our business plan or respond to competitive pressures, any of~~ which could adversely affect the ~~NAMining~~Contract Mining business, operating results and financial condition.

NAMining faces competition from aggregates producers that choose to self-perform mining operations and from other mining companies.

NAMining faces competition from existing and prospective customers that are capable of performing, or engaging other companies to perform the services NAMining provides. NAMining cannot be certain that our existing customers will continue to outsource these services to NAMining in the future, which could adversely affect the NAMining business, operating results and financial condition.

We are subject to risks involved in the development of new mining projects.

From time to time, we seek to develop new mining projects, including the Thacker Pass project. The risks associated with such projects can be substantial. New mining projects can take up to several years to complete, are complex and require significant capital expenditures. These projects are subject to significant risks, including delays or reductions in making capital expenditures by ~~NAMining~~Contract Mining's customers, timely regulatory approvals, extreme weather events, unexpected increases in the cost of required materials, and disputes with third party providers of materials, equipment or services, and a completed project may not yield the anticipated operational or financial benefit, any of which could have a material adverse effect on our business, financial condition and results of operations.

~~NAMining~~Contract Mining operations are currently geographically concentrated and therefore subject to regional economic risk, regulatory conditions, natural disasters, severe weather events or other circumstances affecting Florida.

As of December 31, ~~2024~~2025, over 7580% of the ~~quarries~~Contract ~~NAMining~~Mining ~~operates~~segment's quarries are located in Florida. A prolonged economic downturn or adverse change in regulatory conditions in the Florida mining or construction industry could result in a significant reduction in demand for ~~NAMining’s~~our services. The occurrence of one or more natural disasters, severe weather events, terrorist attacks, or disruptive political events in Florida could adversely affect the ~~NAMining~~Contract Mining business.

~~Risks related to the Minerals Management segment~~18

We have no control over the timing of the development and operation of our natural gas, oil and coal reserves extracted by third parties.

We own mineral and royalty interests in the continental United States. 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. We primarily derive income from royalty-based leases under which lessees make payments to us based on their sale of natural gas, oil and coal. Future royalty-based income is dependent on the number of oil and gas wells being developed and operated on our mineral acreage. The decision to pursue development and operation of oil and gas wells is made by third-party operators, not by us, and depends on a number of factors outside of our control, including fluctuations in commodity prices (primarily natural gas), regulatory risk, our lessees' willingness and ability to incur well-development and other operating costs, the rate of production of the reserves and changes in the availability and continuing development of infrastructure. Lower commodity prices may reduce the amount of oil and natural gas that third-party operators can produce economically. In the event that new federal or state restrictions related to the hydraulic fracturing process are adopted in areas where we own mineral and royalty interests, our lessees may incur additional costs or permitting requirements to comply with such requirements that may be significant and could result in added restrictions, delays or curtailments in the pursuit of exploration, development, or production activities. In addition, if a lessee were to experience financial difficulty, the lessee might not be able to pay our royalty payments or continue operations. A failure on the part of the lessee to make royalty payments may give us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement lessee. However, we may not be able to find a replacement lessee or might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, if we are able to enter into a new

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~~lease~~Risks ~~with~~related ato ~~new lessee,~~ the ~~replacement~~Minerals ~~lessee~~and ~~may~~Royalties ~~not achieve the same levels of production or sales prices as the lessee it replaced. Any of these risks could materially reduce our expected royalty income and profitability.~~segment

We have no control over the timing of the development and operation of our natural gas, oil and coal reserves extracted by third parties.

We own mineral and royalty interests in the continental United States. The Minerals and Royalties segment does not currently have any material investments under which it would be required to bear the cost of exploration, production or development. We primarily derive income from royalty-based leases under which lessees make payments to us based on their sale of natural gas, oil and coal. Future royalty-based income is dependent on the number of oil and gas wells being developed and operated on our mineral acreage. The decision to pursue development and operation of oil and gas wells is made by third-party operators, not by us, and depends on a number of factors outside of our control, including fluctuations in commodity prices, regulatory risk, our lessees' willingness and ability to incur well-development and other operating costs, the rate of production of the reserves and changes in the availability and continuing development of infrastructure. Lower commodity prices and/or increased costs may reduce the amount of oil and natural gas that third-party operators can produce economically. In addition, if a lessee were to experience financial difficulty, the lessee might not be able to pay our royalty payments or continue operations. A failure on the part of the lessee to make royalty payments may give us certain rights; and if possible, we would seek a replacement lessee. However, we may not be able to find a replacement lessee or might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, if we are able to enter into a new lease with a new lessee, the replacement lessee may not achieve the same levels of production or sales prices as the lessee it replaced. Any of these risks could materially reduce our expected royalty income and profitability.

Minerals are a depleting asset. Unless we replace existing mineral and royalty interests with new mineral and royalty interests and third-party lessees develop those mineral and royalty interests, our reserves and royalty income will decline.

Producing oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless our third-party lessees conduct successful ongoing well development activities or we continually acquire mineral and royalty interests, production and income related to our mineral and royalty interests will decline as those reserves are depleted. The future cash flow and results of operations of the Minerals ~~Management~~and Royalties segment are highly dependent on third-party operators’ success in developing our current and future mineral and royalty interests. These operators may not have access to the capital needed to develop our mineral interests. We may not be able to acquire or find sufficient additional mineral and royalty interests to replace third-party operators' current and future production. Further, the decline curve we use to project future royalty income is subject to numerous assumptions and limitations. ~~Natural gas wells have high initial production rates and follow a natural decline before settling into relatively stable, long-term production.~~ Decline rates can vary due to factors like well depth, well length, formation pressure, and facility design. Any of these risks could materially reduce our expected royalty income and profitability.

Substantially all of the Minerals ~~Management~~and Royalties segment’s revenues are derived from royalty payments that are based on the price at which oil and natural gas produced from the acreage underlying our interests are sold. Prices of oil and natural gas are volatile due to factors beyond our control. A substantial or extended decline in commodity prices may adversely affect the Minerals ~~Management~~and Royalties segment’s financial condition or results of operations.

The Minerals ~~Management~~and Royalties segment’s revenues and operating results depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in: supply and demand, including if energy supply exceeds demand; market uncertainty and a variety of additional factors that are beyond our control; market expectations about future prices of oil and natural gas; the level of global oil and natural gas exploration and production; the cost of exploring for, developing, producing and delivering oil and natural gas; the price and quantity of foreign imports and U.S. exports of oil and natural gas; the level of U.S. domestic production; political and economic conditions in oil producing regions; the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; trading in oil and natural gas derivative contracts; the level of consumer product demand; weather conditions and natural disasters; technological advances affecting energy consumption, energy storage and energy supply; domestic and foreign governmental regulations and taxes; the continued threat of terrorism and the impact of military and other action, including ongoing conflicts in foreign nations and associated oil and natural gas import bans as well as economic sanctions ~~such as those imposed by the U.S. on oil and gas exports from Iran~~; the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; the price and availability of alternative fuels; volatility in the political, legal and regulatory environments ~~due to the U.S. presidential election~~; and overall domestic and global economic conditions. A substantial or extended decline in commodity prices may adversely affect the Minerals ~~Management~~and Royalties segment’s financial condition or results of operations.

The marketability of oil and natural gas production is dependent upon transportation, pipelines and refining facilities and continued operation of the U.S. power grid. Any limitation in the availability of these items could interfere with our third-party lessee’s ability to market oil and natural gas production and may adversely affect the Minerals ~~Management~~and Royalties segment’s financial condition or results of operations.

The marketability of our third-party lessee’s production depends in part on the availability, proximity, and capacity of pipelines, tanker trucks, and other transportation methods, and processing and refining facilities owned by third parties as well as continued reliable operation of the U.S power grid. Any significant disruption in the U.S. power grid, gathering system or transportation, processing, or refining-facility capacity could reduce our third-party lessee’s ability to market oil production and may adversely affect the Minerals Management segment’s financial condition or results of operations.19

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The marketability of our third-party lessee’s production depends in part on the availability, proximity, and capacity of pipelines, tanker trucks, and other transportation methods, and processing and refining facilities owned by third parties as well as continued reliable operation of the U.S power grid. Any significant disruption in the U.S. power grid, gathering system or transportation, processing, or refining-facility capacity could reduce our third-party lessee’s ability to market oil production and may adversely affect the Minerals and Royalties segment’s financial condition or results of operations.

Risks related to long-term growth strategy

Our investments in mitigation solutions, comprehensive reclamation and restoration construction services as well as solar and other energy-related development projects are subject to substantial risks and uncertainties.

There are risks associated with NACCO's ability to execute on our longer term growth strategy, including our investment in mitigation solutions, comprehensive reclamation and restoration construction services as well as ~~clean~~other energy-related projects through our Mitigation Resources of North America and ReGen Resources businesses, and our ability to develop and manage such projects profitably. These include political and regulatory developments that may make it more costly, or impossible, to pursue these business opportunities, logistical risks and potential delays related to construction, permitting and regulatory approvals; operational risk that the projects will not perform according to expectations; weather conditions or other factors beyond our control. General concerns about the fundamental soundness of the economy may cause customers to defer projects, even if they have available financing. Prolonged uncertainties in the capital markets, or the returns of constrained capital market conditions, could have adverse effects on our customers. All of the aforementioned risks could reduce the viability of project development, which would adversely affect our financial condition and results of operations.

23The OBBBA includes substantial changes to U.S. solar energy tax policy which could have a material impact on the

~~Table~~projects being developed by ReGen Resources. Current projects in development include solar arrays, solar-gas hybrid projects, thermal generation and carbon capture primarily on reclaimed mining properties in Louisiana, Mississippi, Ohio, Pennsylvania and Texas. ReGen develops energy infrastructure projects directly as well as through joint ventures. Our investments in solar projects are dependent, in part, on federal tax incentives to preserve economic value. We believe all current solar projects have been safe harbored in order to preserve tax credit eligibility. We have approximately $8.4 million of ~~Contents~~capitalized assets associated with our solar projects. We have incurred, and will continue to incur, costs in connection with these projects and the results of operations and/or return on investment could be lower than anticipated. These projects face the risk that the current state regulatory programs and tax laws may expire or be adversely modified and could have a material adverse effect on our operating results and financial condition.

~~control.~~Operating ~~All of the aforementioned risks could reduce the viability of project development. We have and will continue to incur costs in connection with these projects and the~~ results ~~of operations and/or return on investment could be negative or lower than anticipated and we~~ may ~~need~~vary tosignificantly ~~write-down~~from ~~the~~period ~~value of capitalized assets associated with these projects. Furthermore, our ability~~ to ~~forecast~~period ~~results may be hindered or inaccurate~~ and ~~the projects may not perform as predicted. Even if these projects~~ are ~~profitable~~inherently ~~in the long term, they may not be profitable in the short term, and results of operations are unlikely to be even quarter over quarter~~unpredictable.

InDemand ~~addition,~~for our ~~investments~~mitigation credits and mitigation services has been, and will likely continue to be, cyclical in ~~solar~~nature and ~~other~~vulnerable ~~energy~~to ~~projects~~downturns ~~are~~in ~~dependent~~the general economy, as well as downturns in government infrastructure spending. We base our planned operating expenses in part on our expectations of future revenue, ~~upon~~and ~~current~~a ~~state~~significant ~~regulatory~~portion ~~incentives~~of our expenses are fixed in the short-term. We have and ~~federal~~will ~~tax~~continue ~~credits~~to incur costs in ~~order~~connection ~~for~~with these projects and the results of operations and/or return on investment could be negative or lower than anticipated and we may need to write-down the value of capitalized assets associated with these projects. Furthermore, our ability to forecast results may be ~~economically~~hindered ~~viable~~or inaccurate and the projects may not perform as predicted. ~~These~~Even if these projects ~~face~~are profitable in the ~~risk~~long ~~that~~term, ~~the~~they ~~current~~may ~~state~~not ~~regulatory~~be ~~programs~~profitable in the short term, and ~~tax~~results ~~laws~~of ~~may~~operations ~~expire~~will ornot be ~~adversely~~even ~~modified~~quarter over quarter, and this could have a material adverse effect on our operating results and financial condition.

Risks related to corporate structure

The amount and frequency of dividend payments made on NACCO's common stock could change.

The Board of Directors has the power to determine the amount and frequency of the payment of dividends. Decisions regarding whether or not to pay dividends and the amount of any dividends are based on earnings, capital and future expense requirements, financial conditions and other factors the Board of Directors may consider. Accordingly, holders of our common stock should not rely on past payments of dividends in a particular amount as an indication of the amount of dividends that will be paid in the future.

The price of NACCO's securities may be volatile.

The price of our common stock may fluctuate due to a variety of market and industry factors that may materially reduce the market price of NACCO's common stock regardless of operating performance, including, among others: (i) actual or anticipated fluctuations in our quarterly and annual results and those of other public companies in the industry; (ii) industry cycles and trends; (iii) changes in government regulation; (iv) ~~potential or actual~~ military conflicts, orinclusive of acts of terrorism; (v) supply chain disruptions, inclusive of tariff effects; (vi) announcements concerning NACCO, our customers or competitors; (vivii) lack of trading liquidity as a result of low trading volumes could make it difficult for investors to sell shares; and (~~vii~~viii) the general state of the securities market. In addition, the stock market in general has experienced significant volatility that often has been unrelated to the operating performance of companies whose shares are traded. These market fluctuations could adversely affect the trading price of our common stock, regardless of NACCO's actual operating performance. As a result of all of these factors, investors in our common stock may not be able to resell their stock at or above the price they paid or at all. Further, we could be the subject of securities class action litigation due to any such stock price volatility, which could divert management’s attention and have a material adverse effect on our operating results.

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of the securities market. In addition, the stock market in general has experienced significant volatility that often has been unrelated to the operating performance of companies whose shares are traded. These market fluctuations could adversely affect the trading price of our common stock, regardless of NACCO's actual operating performance. As a result of all of these factors, investors in our common stock may not be able to resell their stock at or above the price they paid or at all. Further, we could be the subject of securities class action litigation due to any such stock price volatility, which could divert management’s attention and have a material adverse effect on our operating results.

NACCO's certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.

Provisions contained in our certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire us, even if doing so might be beneficial to NACCO's stockholders. Provisions in our by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to affect certain corporate actions. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control.

Our stock repurchase program could affect the price of NACCO’s common stock and increase volatility and may not enhance long-term shareholder value.

Our Board of Directors has authorized a stock repurchase program. The timing and amount of any repurchases under the stock repurchase program are determined at the discretion of our management based on a number of factors, including the availability of capital, other capital allocation alternatives, market conditions for our Class A common stock and other legal and contractual restrictions. The stock repurchase program does not require us to acquire any specific number of shares and may be modified, suspended, extended or terminated without prior notice and may be executed through open market purchases, privately negotiated transactions or otherwise.

Repurchases under the stock repurchase program could affect the price of our Class A common stock. The existence of a stock repurchase program could cause the price of our Class A common stock to be higher than it would be in the absence of such a program and could potentially reduce the market liquidity for our Class A common stock. There can be no assurance that any stock repurchases will enhance shareholder value because the market price of our Class A common stock may decline below the levels at which we repurchased the shares. Although the stock repurchase program is intended to enhance long-term shareholder value, there is no assurance that it will do so and short-term price fluctuations in the Class A common stock could reduce the program’s effectiveness. Furthermore, the stock repurchase program does not obligate us to repurchase any dollar amount or number of shares of our Class A common stock, and it may be suspended or discontinued at any time and any suspension or discontinuation could cause the market price of our Class A common stock to decline.

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NACCO is a smaller reporting company and cannot be certain if the reduced disclosure requirements applicable to smaller reporting companies will make our common stock less attractive to investors.

We are currently a smaller reporting company as defined in the Securities Exchange Act of 1934, and thus allowed to provide simplified executive compensation disclosures and other decreased disclosure in SEC filings. The reduced disclosures may make it more difficult to compare our performance with other public companies.

NACCO cannot predict whether investors will find our common stock less attractive because of these exemptions. If some investors find NACCO's common stock less attractive as a result, there may be a less active trading market for our common stock and the stock price may be more volatile.

Certain members of our extended founding family own a substantial amount of our Class A and Class B common stock and, if they were to act in concert, could control the outcome of director elections and other stockholder votes on significant corporate actions.

We have two classes of common stock: Class A common stock and Class B common stock. Holders of Class A common stock are entitled to cast one vote per share and, as of December 31, ~~2024~~2025, accounted for approximately 27 percent of our voting power. Holders of Class B common stock are entitled to cast ten votes per share and, as of December 31, ~~2024~~2025, accounted for our remaining voting power. As of December 31, ~~2024~~2025, certain members of our extended founding family held approximately 3635 percent of our outstanding Class A common stock and approximately 99 percent of our outstanding Class B common stock. On the basis of this common stock ownership, certain members of our extended founding family could have exercised approximately 8281 percent of our total voting power. Although there is no voting agreement among such extended family members, in writing or otherwise, if they were to act in concert, they could control the outcome of director elections and other stockholder votes on significant corporate actions, such as certain amendments to our certificate of incorporation and our sale or the sale of our assets. Because certain members of our extended founding family could prevent other stockholders from exercising significant influence over significant corporate actions, we may be a less attractive takeover target, which could adversely affect the market price of our common stock.

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General Risk Factors

Our effective income tax rate could be volatile and materially change as a result of changes in tax laws, mix of earnings and other factors.

We are subject to income taxes in the United States and the effective income tax rate is impacted by certain U.S. federal income tax benefits currently available to coal mining and oil and gas exploration and development companies. Future results of operations could be affected by changes in our effective income tax rate as a result of an increase in the statutory tax rate or the reduction or elimination of percentage depletion as well as changes in the mix of earnings between entities that benefit from percentage depletion and those that do not.

Current and future capital and credit market conditions could adversely affect our ability to obtain bank financing on reasonable terms. Certain financial institutions have acted to limit available financing for companies in the fossil fuel industry, including coal mining, which could result in increases in costs of borrowing or in our ability to maintain financing at current levels.

We may be unable to obtain financing on reasonable terms. Historically, we have addressed our liquidity needs (including funds required to pay dividends and fund working capital and planned capital expenditures) with operating cash flow and borrowings under credit facilities. Our wholly-owned subsidiary has a revolving line of credit of up to $200.0 million that expires in September 2028. Our ability to access the capital markets and the costs and terms of available financing depends on many factors~~, including perceived credit risks of companies with coal and/or oil and gas exposure as a result of current market sentiment for fossil fuels~~. Certain financial institutions have taken actions to limit available financing to entities that produce or use fossil fuels. The volatility in the energy industry and additional perceived credit risks of companies with coal and/or oil and gas exposure has resulted in traditional bank lenders seeking to reduce or eliminate their lending exposure to these companies. An inability to obtain bank financing, or refinance with terms that are as favorable as the existing terms of such indebtedness, could have a material adverse effect on our operating results and financial condition.

Failure to obtain financial assurance to secure reclamation and other long-term obligations, including surety bonds and letters of credit on acceptable terms, could affect NACCO's ability to mine.

Federal and state laws require us to provide financial assurance or financial security to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers’ compensation and black lung benefit costs, leases, transmission interconnection construction costs, power purchase agreement delivery obligations and other obligations. Future federal and state laws and regulations, regional transmission organizations and power purchase agreement customers may require higher amounts of financial security, including as a result of changes to certain factors used to calculate the bonding or security amounts. Bond issuers may demand higher fees or additional collateral, including cash or letters of credit or other terms less favorable upon renewals. As we are required by state and federal law to have bonds or other acceptable security in place before mining can commence or for certain projects to move forward, the failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect NACCO's ability to mine. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our financing arrangements. Any such factors, could have a material adverse impact on our liquidity and financial position. If we are unable to meet collateral requirements and cannot otherwise obtain or retain required surety bonds, it may be unable to satisfy legal requirements necessary to conduct mining operations. Difficulty in acquiring surety bonds, or additional collateral requirements, would increase our costs and likely require greater use of alternative sources of funding for this purpose, which would reduce our liquidity.

25Insurance coverage is increasingly expensive, contains more stringent terms and may be difficult to obtain in the future.

~~Table~~We hold a number of ~~Contents~~insurance policies, including director and officers’ liability and property and casualty insurance coverages. If we make significant insurance claims under our insurance policies, such claims may have a material adverse effect on our ability to obtain future insurance coverage at commercially reasonable rates. Limited, or an inability to obtain, insurance coverage, significant increases in the premiums or deductibles of insurance, or losses in excess of our liability insurance coverage limits, could have a material adverse effect on our operating results and financial condition.

to calculate the bonding or security amounts. Bond issuers may demand higher fees or additional collateral, including cash or letters of credit or other terms less favorable upon renewals. As we are required by state and federal law to have bonds or other acceptable security in place before mining can commence or for certain projects to move forward, the failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect NACCO's ability to mine. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our financing arrangements. In addition, as a result of increasing credit pressures on the coal industry, it is possible that surety bond providers could demand other forms of collateral as a condition to providing or maintaining surety bonds. Any such demands, could have a material adverse impact on our liquidity and financial position. If we are unable to meet collateral requirements and cannot otherwise obtain or retain required surety bonds, it may be unable to satisfy legal requirements necessary to conduct mining operations. Difficulty in acquiring surety bonds, or additional collateral requirements, would increase our costs and likely require greater use of alternative sources of funding for this purpose, which would reduce our liquidity.

Insurance coverage is increasingly expensive, contains more stringent terms and may be difficult to obtain in the future. A number of global insurance companies have taken steps to limit coverage for companies in the fossil fuel industry, including coal mining, which could result in significant increases in costs of insurance or in our ability to maintain insurance coverage at current levels.

We hold a number of insurance policies, including director and officers’ liability and property and casualty insurance coverages. Because we are involved in coal mining, costs of insurance may increase substantially or insurance carriers may limit or decide not to insure us in the future. In addition, if we make significant insurance claims under our insurance policies, such claims may have a material adverse effect on our ability to obtain future insurance coverage at commercially reasonable rates. Limited, or an inability to obtain, insurance coverage, significant increases in the premiums or deductibles of insurance, or losses in excess of our liability insurance coverage limits, could have a material adverse effect on our operating results and financial condition.

Increasing emphasis and changing expectations with respect to environmental, social and governance matters may impose additional costs on us or expose us to new or additional risks.

Expectations relating to environmental, social and governance (ESG) matters have been rapidly evolving. Government organizations are enhancing or advancing legal, regulatory and disclosure requirements specific to ESG matters. The heightened focus on ESG issues requires the continuous monitoring of various and evolving laws, regulations, standards and expectations and the associated reporting requirements. Investor advocacy groups, certain institutional investors, investment funds and other influential investors are also increasingly focused on ESG practices. We could face pressures from investors, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability. Investors may request that we implement ESG procedures or standards as a condition to maintain their investment or to make further investments. Lenders and insurers may also limit lending to and insuring of companies that do not meet certain ESG measures endorsed by them. Additionally, we may face reputational challenges in the event our ESG practices are inconsistent with the third-party views of acceptable ESG practices. Further, there is an increasing number of state-level anti-ESG initiatives in the United States that may conflict with other regulatory requirements or various stakeholders’ expectations. Companies which do not adapt to or comply with regulatory, investor or stakeholder expectations and standards, which are evolving, or which are perceived to have not responded appropriately, may suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely affected.

We may be subject to litigation seeking to hold energy companies accountable for the effects of climate change.

Increasing attention to climate change risk has also resulted in a recent trend of governmental investigations and private litigation by local and state governmental agencies as well as private plaintiffs in an effort to hold energy companies accountable for the alleged effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, oil and gas companies alleging that their operations are contributing to climate change. We could incur substantial legal costs associated with defending such lawsuits in the future. Government entities in certain states have brought similar claims seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of emissions attributable to those fuels or for other grounds related to climate change, such as improper disclosure of climate change risks. Those lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. We have not been made a party to these suits, but it is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants.

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Our business could suffer if NACCO’s information technology systems are disrupted, cease to operate effectively or if we experience a security breach, a cyber incident or cyber attack.

Like many other companies, we are the target of malicious cyber attack attempts in the normal course of business. Cybersecurity incidents involving businesses and other institutions are on the rise. Cyber threats are rapidly evolving and those threats and the means for obtaining access to information in digital and other storage media are becoming increasingly sophisticated. Cyber threats and cyber attackers can be sponsored by nation states or sophisticated criminal organizations or be the work of independent hackers. The rapid evolution and increased availability of artificial intelligence (AI) may intensify cybersecurity risks by making cyber-attacks more sophisticated and cybersecurity incidents more difficult to detect, contain and mitigate. As threat actors adopt and deploy AI tools, the speed and sophistication of cyber threats and privacy risks may increase across our environment and those of our customers and vendors.

As cyber threats evolve and become more difficult to detect and successfully defend against, one or more cyber attacks might defeat our, or a third-party service provider's, security measures in the future. Employee error or other irregularities may also result in a failure of security measures and a breach of information systems. Moreover, hardware, software or applications we may use have inherent defects of design, manufacture or operations or could be inadvertently or intentionally implemented or used in a manner that could compromise information security.

A security breach and loss of information may not be discovered for a significant period of time after it occurs. Any compromise of data security could result in a violation of applicable privacy and other laws or standards, the loss of valuable business data, or a disruption of our business. A security breach involving the misappropriation, loss or other unauthorized disclosure of sensitive or confidential information could give rise to unwanted media attention, materially damage customer relationships and our reputation, and result in fines, fees, or liabilities, which may not be covered by insurance policies.

We rely on information technology systems to operate our business and to record and process transactions; respond to customer inquiries; purchase supplies; provide services; deliver inventory on a timely basis; and maintain cost-efficient operations. Despite our efforts, our information technology systems may be vulnerable, from time to time, to damage or interruption from user error, computer viruses, power outages, third-party intrusions and other technical malfunctions.

Through our business operations, we collect and store confidential information from our customers and vendors and personal information and other confidential information from our employees. Although we have taken steps designed to safeguard such information, there can be no assurance that such information will be protected against unauthorized access, use or disclosure. Unauthorized parties may penetrate our or our vendors’ network security and, if successful, misappropriate such information. Additionally, methods to obtain unauthorized access to confidential information change frequently and may be difficult to detect, which can impact our ability to respond appropriately.

We could be subject to liability for failure to comply with privacy and information security laws, for failing to protect personal information or for failing to respond appropriately. Loss, unauthorized access to, or misuse of confidential or personal information could disrupt our operations, damage our reputation, and expose us to claims from customers, financial institutions, regulators, employees and other persons, any of which could have an adverse effect on our business, financial condition and results of operations.

Security breaches, cyber incidents or cyber attacks could include, among other things, computer viruses, malicious or destructive code, ransomware, social engineering attacks (including phishing and impersonation), hacking, denial of service attacks and other attacks. Cybersecurity threats to, and incidents involving, vendors and other third-parties who support our activities could impact the business. We are continuously installing new and upgrading existing information technology systems. We use employee awareness training around phishing, malware, and other cyber risks. We believe these incidents are likely to continue and are unable to predict the direct or indirect impact of future attacks or breaches to business operations.

Our operations could be disrupted by natural or human causes beyond our control.

Our operations are subject to disruption from natural or human causes beyond our control, including physical risks from hurricanes, severe storms, floods and other forms of severe weather, accidents, fires, earthquakes, terrorist acts and epidemic or pandemic diseases, any of which could result in suspension of operations or harm to people or the environment. While all of our operations are located in the United States, we participate in a global supply chain, and if governments regulate or restrict the flow of labor or products or impede the travel of our personnel, our ability to conduct normal business operations could be impacted which could adversely affect our results of operations and liquidity.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

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Item 1C. CYBERSECURITY

Cybersecurity continues to be a key governance priority for us. NACCO maintains a cybersecurity program that is aligned with our business and has established policies and processes for assessing, identifying, and managing material risk from cybersecurity threats, which have been integrated into our overall risk management processes and governance structure.

We have implemented and invested in, and will continue to implement and invest in, controls, technologies, and resources (both internal and external) that are designed to identify, protect against, detect, respond to and mitigate cybersecurity risks, in alignment with frameworks established by the National Institute of Standards and Technology. These include, but are not limited to, internal reporting mechanisms, monitoring and detection tools, threat intelligence, and general and role-based training. NACCO's commitment to cybersecurity emphasizes cultivating a security-minded culture through education and training that reflect best practices and improved cybersecurity awareness. We also maintain third party management processes to identify and manage the cybersecurity risks associated with third party service providers. We periodically evaluate our cybersecurity program internally and by engaging with consultants to conduct reviews and assessments of the program. Such reviews and assessments may include penetration testing, maturity assessments as well as table-top and other exercises with subsequent remediation of key findings. Additionally, we have a Cybersecurity Task Force in place that is comprised of individuals across various departments within our organization including information systems, legal, finance, human resources and internal audit which meets regularly to further advance our cybersecurity strategy.

Our Board of Directors (Board) oversees NACCO's risk management. Our full Board regularly reviews information provided by management to oversee risk identification, risk management and risk mitigation strategies. The Audit Review Committee assists the Board with cybersecurity risk oversight. The Audit Review Committee is responsible for regularly reviewing and discussing with management risk exposure relating to cybersecurity,. ~~which~~This process includes reviewing the state of our cybersecurity program, ~~and~~discussing emerging cybersecurity developments, ~~and~~including ~~threats~~AI, asand ~~well~~monitoring as the steps that management has taken to ~~monitor and~~ mitigate such exposure. In ~~2024~~2025, our Board and the Audit Review Committee received periodic updates throughout the year on cybersecurity matters and these updates are part of their standing agendas.

Our Chief Information Security Officer (CISO) leads NACCO's cybersecurity program and is responsible for the management of our cybersecurity risks. The CISO has extensive cybersecurity knowledge and skills gained from over 30 years of technical and business experience, including as General Manager & President of MLMC, Vice President of Mississippi Operations and Vice President of Innovation & Technology. The CISO holds a bachelor’s degree in engineering, an executive MBA, and certifications in cybersecurity from Harvard. Additionally, the CISO successfully completed an Executive course through Northwestern’s Kellogg School of Management focused on artificial intelligence during 2024. The CISO reports directly to the President and Chief Executive Officer. The CISO manages a team of internal and external resources that have expertise and experience in cybersecurity. The CISO is informed of cybersecurity incidents by the cybersecurity team, which is generally responsible for monitoring the prevention, detection, mitigation, and remediation of cybersecurity incidents. We have an established process governing our assessment, response and internal and external notifications upon the occurrence of a cybersecurity incident, including evaluation of the potential impacts of cybersecurity incidents to determine materiality. Depending on the nature and severity of an incident, this process provides for escalation procedures upon discovery of material cybersecurity risks, including notification to our executive management and/or Board.

As of the date of this filing, our business strategy, results of operations, and financial condition have not been materially impacted as a result of any previously identified cybersecurity incidents; however, NACCO cannot provide assurance that we will not be materially impacted in the future by such risks or any future material incidents. We recognize the constantly evolving nature of cyber threats and are committed to cultivating a strong security culture, maintaining vigilance and continuously enhancing our cybersecurity systems and controls. For additional information regarding our cybersecurity risks, please refer to Item 1A - Risk Factors on page 1815.

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Item 2. PROPERTIES

Utility Coal Mining Segment - Operations

NACCO-owned Properties

1.0 INTRODUCTION

Information concerning our mining properties in this Form 10-K have been prepared in accordance with the requirements of subpart 1300 of Regulation S-K. As used in this Report on Form 10-K, the terms mineral resource, measured mineral resource, indicated mineral resource, inferred mineral resource, mineral reserve, proven mineral reserve and probable mineral reserve are defined and used in accordance with subpart 1300 of Regulation S-K. Under subpart 1300 of Regulation S-K, mineral resources may not be classified as mineral reserves unless the determination has been made by a qualified person that the mineral resources can be the basis of an economically viable project. Readers are specifically cautioned not to assume that any part or all of the mineral deposits (including any mineral resources) in these categories will ever be converted into mineral reserves, as defined by the subpart 1300 of Regulation S-K.

Readers are cautioned that, except for that portion of mineral resources classified as mineral reserves, mineral resources do not have demonstrated economic value. Inferred mineral resources are estimates based on limited geological evidence and sampling and have too high of a degree of uncertainty as to their existence to apply relevant technical and economic factors likely to influence the prospects of economic extraction in a manner useful for evaluation of economic viability. Estimates of inferred mineral resources may not be converted to a mineral reserve. It cannot be assumed that all or any part of an inferred mineral resource will ever be upgraded to a higher category. A significant amount of exploration must be completed in order to determine whether an inferred mineral resource may be upgraded to a higher category. Therefore, readers are cautioned not to assume that all or any part of an inferred mineral resource exists, that it can be the basis of an economically viable project, or that it will ever be upgraded to a higher category. Likewise, readers are cautioned not to assume that all or any part of measured or indicated mineral resources will ever be converted to mineral reserves. See Item 1A - Risk Factors on page 1815.

The information that follows is derived, for the most part, from, and in some instances is an extract from, the technical report summary (TRS) prepared in compliance with the Item 601(b)(96) and subpart 1300 of Regulation S-K. The TRS was prepared by certain of our employees. Portions of the following information are based on assumptions, qualifications and procedures that are not fully described herein. Reference should be made to the full text of the TRS, incorporated herein by reference and made a part of this Report on Form 10-K. The information regarding MLMC was reviewed by our employees that are qualified persons as defined by subpart 1300 of Regulation S-K.

Coteau, Falkirk, Coyote Creek and MLMC, each wholly-owned subsidiaries of NACCO, operate surface coal mines under long-term contracts with power generation companies pursuant to a service-based business model.

Locations of the properties subject to SEC Section 1300 reporting are shown in Figure 1.1 Surface Coal Mines Operational During ~~2024~~2025 Subject to SEC Section 1300 Reporting.

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Figure 1.1 Surface Coal Mines Operational During ~~2024~~2025 Subject to SEC Section 1300 Reporting

A summary of coal production at the Mines subject to SEC Section 1300 Reporting for the past three years has been tabulated and is presented on Table 1.1 Production Summary.

	Tons (in millions)
	2022	2023	2024
	2023	2024	2025
The Coteau Properties Company	1311.4	11.49	11.93
The Falkirk Mining Company	76.6	67.65	7.53
Coyote Creek Mining Company	12.82	21.29	1.98
Mississippi Lignite Mining Company	3.2.7	21.79	12.97
Totals	2622.09	2223.92	23.21

Table 1.1 Production Summary

2.0 MINING PROPERTIES SUBJECT TO SUBPART 1300 OF REGULATION S-K REPORTING

2.1 Red Hills Mine — Mississippi Lignite Mining Company

MLMC is the owner and operator of the Red Hills Mine. The Red Hills Mine is a lignite surface mine in production. Prior to MLMC, there were no previous mining operations on the Red Hills Mine property.

The MLMC contract is the only operating coal contract in which we are responsible for all operating costs, capital requirements and final mine reclamation; therefore, MLMC is consolidated within our financial statements. MLMC sells coal to its customer at a contractually agreed-upon price which adjusts monthly, primarily based on changes in the level of established indices which reflect general U.S. inflation rates. Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred.

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A summary of coal production at MLMC for the past three years has been tabulated and is presented on Table 2.1 Production Summary.

	Tons (in millions)
	2022	2023	2024
	2023	2024	2025
Mississippi Lignite Mining Company	3.2.7	21.79	12.97

Table 2.1 Production Summary

The Red Hills Mine generally produces between 2 million and 3 million tons of lignite coal annually. The Red Hills Mine started operations in 2000 for plant commissioning, with initial commercial deliveries starting in 2001, and full production and commercial deliveries starting in 2002. All production from the mine is delivered to MLMC's customer's Red Hills Power Plant. During 2023, MLMC received notice from its customer related to a boiler issue at the Red Hills Power Plant that began on December 15, 2023. While this issue has been resolved, it resulted in a reduction in customer demand which had a significant impact on our 2024 results of operations.

The Red Hills Mine, operated by MLMC, is located approximately 120 miles northeast of Jackson, Mississippi (Figure 2.1). The entrance to the mine is by means of a paved road located approximately one mile west of Highway 9. MLMC owns in fee approximately 8,~~090~~337 acres of surface interest and 5,~~150~~436 acres of coal interests. MLMC holds leases granting the right to mine approximately 54,~~423~~660 acres of coal interests and the right to utilize approximately 4,~~890~~384 acres of surface interests. MLMC holds subleases under which it has the right to mine approximately 1,~~683~~860 acres of coal interest. The majority of the leases held by MLMC were originally acquired during the mid-1970s to the early 1980s with terms extending 50 years, many of which can be further extended by the continuation of mining operations. The lignite deposits of the Gulf Coast are found primarily in a narrow band of strata that outcrops/subcrops along the margin of the Mississippi Embayment. The potentially exploitable tertiary lignites in Mississippi are found in the Wilcox Group. The outcropping Wilcox is composed predominately of non-marine sediments deposited on a broad flat plain.

The towns of Ackerman, Eupora, Starkville, Louisville, Kosciusko, and numerous smaller communities are within a 40-mile radius of the Red Hills Mine and provide a vast employment base. Furthermore, Mississippi State University (MSU) is located approximately 30 miles east of the mine in Starkville. MLMC has a history of partnership with MSU as well as the local community colleges for science, technology, engineering, and mathematics (STEM) research and skilled trades training.

The Red Hills Mine sources power for mine office facilities and operations from 4-County Electric Power Association, and water for the mine office facilities from the Reform Water Association. Fuel for equipment is supplied by a local vendor. The Red Hills Mine has, or is currently constructing, all supporting infrastructure for mining operations.

Local access to the Red Hills Mine is by way of Highway 9 between Ackerman, Mississippi and Eupora, Mississippi which connects to Pensacola Road that leads to the Red Hills Mine paved access road. Pensacola Road connects with Highway 9 approximately 5 miles north of Ackerman, MS. The mine road is approximately 1 mile west from Highway 9 along Pensacola Road.

Travel to the Red Hills Mine by air is possible using the Jackson-Medgar Wiley Evers International Airport in Jackson, Mississippi, approximately 104 miles south of the mine, and then using ground transportation, traveling via Highway 25, Highway 15, and Highway 9. Alternatively, the Golden Triangle Regional Airport is a smaller airport approximately 50 miles from the Red Hills Mine by means of Highway 82 west, Highway 15 south, and Highway 9 north.

The Red Hills Mine is in close proximity to river ports of the Tennessee-Tombigbee Waterway and the Mississippi River. The Lowndes County Port is approximately 60 miles east of the mine. The Port of Greenville is approximately 135 miles west of the mine, and the Port of Vicksburg, approximately 150 miles southwest of the mine. All ports are connected by major state and federal highways.

In addition to transportation via roadways, air and waterways, the Kansas City Southern (KCS) railroad has a depot located approximately 5 miles south of the mine in Ackerman, and is accessible by Highway 9 and Highway 15. MLMC currently has all permits in place for the Red Hills Mine to operate and adhere to a mine plan projected through April 1, 2032. No mineral processing occurs at the Red Hills Mine.

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The geology encountered at the Red Hills Mine is stratigraphic in nature with depositional sequences of sands, silts, clays, and lignite. The vertical repetition of geologic strata facilitated a straightforward setting to establish and study the baseline geological, geochemical, geotechnical, and geohydrological conditions at the Red Hills Mine.

Development of the Red Hills Mine began in 1997, with full commercial deliveries commencing in 2002. The mining operation is comprised of four major equipment fleets. Primary removal of burden is achieved with one 82-cubic yard electric-powered dragline, four large track-type push dozers, and a truck and shovel fleet utilizing a 41-cubic yard electric rope shovel. Lignite is mined using a surface miner or a hydraulic backhoe to load a fleet of end dump haul trucks, and is directly shipped to the RHPP or the lignite stockpile. The overall average quality of the mined lignite seams meets the required power plant quality specifications. Therefore, no mineral processing is performed by MLMC.

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dragline, four large track-type push dozers, and a truck and shovel fleet utilizing a 41-cubic yard electric rope shovel. Lignite is mined using a surface miner or a hydraulic backhoe to load a fleet of end dump haul trucks, and is directly shipped to the RHPP or the lignite stockpile. The overall average quality of the mined lignite seams meets the required power plant quality specifications. Therefore, no mineral processing is performed by MLMC.

The mine office facilities and original equipment fleets at the Red Hills Mine were constructed, acquired, or purchased new during the development stage of the mine. The facilities and equipment are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, MLMC evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

The total cost of the property and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, ~~2024~~2025 is $5254.54 million.

The Red Hills Mine currently has no significant encumbrances to the property. No mining permit violations have been issued at the Red Hills Mine in the past ten years. One notice of violation (NOV) was issued in April 2020 for a water quality exceedance that was determined to not be the fault of Red Hills Mine and no further action was required. A second NOV was issued in June 2022 for a water sampling violation. Both NOVs were not related to the mining permit. Permitting requirements are discussed in Section 17.0 of the TRS.

Figure 2.1 – Red Hills Mine Location

32Mineral Resources and Reserves have been summarized from the December 31, 2024 TRS for MLMC and have been modified from mining depletion. The Mineral Resources and Mineral Reserves as of December 31, 2025 are included as Table 2.2 and Table 2.3. Coal qualities are reported on an as-received moisture basis. Based on the December 31, 2024 TRS, prices in Table 2.2 are based on economic cut-off grades of $34.02 per ton at MLMC and prices in Table 2.3 are based on economic cut-off grades of $34.40 per ton at MLMC.

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Mineral Resources and Reserves have been summarized from the December 31, 2024 TRS for MLMC. The Mineral Resources and Mineral Reserves as of December 31, 2024 are included as Table 2.2 and Table 2.3. Coal qualities are reported on an as-received moisture basis. Based on the December 31, 2024 TRS, prices in Table 2.2 are based on economic cut-off grades of $34.02 per ton at MLMC and prices in Table 2.3 are based on economic cut-off grades of $34.40 per ton at MLMC.

Material assumptions and criteria used in the determination of Mineral Resource and Mineral Reserves reported herein are provided within the filed TRS for the MLMC – Red Hills Mine dated December 31, 2024.

Section 11.0 of the TRS describes the key assumptions, parameters, and methods used for the estimation of Mineral Resources. Assumptions include a maximum cumulative stripping ratio of 18:1 based on an assumed lignite sales price of $34.02 per ton. A further description of the verified drilling data used to model the lignite deposit for estimation of Mineral Resources is provided in Section 7.2 Drilling Exploration, 8.0 Sample Preparation, Analyses, and Security, and Section 9.0 Data Verification.

Section 12.0 of the TRS describes the key assumptions, parameters, and methods used for the estimation of Mineral Reserves, and include the following:

•Maximum stripping ratio: 14:1;

•Mining production rates on a cubic yard and per ton basis remain relatively consistent with historical performance;

•Mining costs on a unit basis remain relatively consistent with historical performance;

•Minimum minable lignite thickness: 1.0 feet;

•Minimum parting thickness before seams are composited: 6.0 inches;

•Maximum depth of mining: approximately 320 feet;

•Lignite density defined by seam from coal core drilling data and modified by dilution parameters and approximately 80 lb/ft³; and

•Recovery rates by seam ranging from 67% to 100%.

Modifying factors including dilution parameters and technical information related to the mining process are described in detail under Section 13.0 Mining Methods. Economic factors to support the Mineral Reserve estimates are described in Section 18.0 Capital and Operating Costs and 19.0 Economic Analyses.

The Mineral Resources as of December 31, ~~2024~~2025 presented in Table 2.2 below have been estimated by applying a series of geologic and physical limits as well as high-level mining and economic constraints. The mining and economic constraints were limited to a level sufficient to support reasonable prospect for future economic extraction of the estimated Mineral Resources. The categorized Mineral Resources reported herein are exclusive of Mineral Reserves.


Lignite Coal	Resource Classification	Tonnage ( Kt)	Grades/Qualities
			Calorific Value (Btu/lb)	Moisture (%wt)	Ash (%wt)	Sulfur (%wt)
Mississippi Lignite Mining Company	Measured	4,400	5,200	44.6	13.0	0.6
Mississippi Lignite Mining Company	Indicated	400	5,180	44.1	13.6	0.6
Mississippi Lignite Mining Company	Measured + Indicated	4,700	5,200	44.5	13.0	0.6
Mississippi Lignite Mining Company	Inferred	100	5,200	45.5	12.0	0.5

Note:

–Mineral Resources estimates have been prepared by a qualified person (QP) employed by NACCO Natural Resources ~~as of December 31, 2024~~.

–Mineral Resources that are not Mineral Reserves do not have demonstrated economic viability and there is no certainty that all or any part of such Mineral Resources will be converted into Mineral Reserves.

–Mineral Resources are in-situ and exclusive of 22.9 million tons (Mt) of Mineral Reserves.

–Mineral Resources are reported using an economic cutoff of $34.02 per ton.

–Resources are presented with a minimum 1 foot seam thickness, a maximum as received moisture basis ash content of 30%, and a minimum calorific value of 4000 BTU/lb on an as received moisture basis cutoff.

–Resources are estimated using Vulcan Software.

–Tonnages and qualities have been rounded to an accuracy level deemed appropriate by the QP. Summation errors due to rounding may exist.

33Table 2.2 Mineral Resources Summary as of December 31, 2025

The Mineral Reserves as of December 31, 2025 presented in Table 2.3 below were determined to be the economically mineable portion of the measured and indicated Mineral Resources after the consideration of modifying factors related to the mining process. Inferred Mineral Resources were not considered for Mineral Reserves.

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Table 2.2 Mineral Resources Summary as of December 31, 2024


Lignite Coal	Reserve Classification	Tonnage (Kt)	Grades/Qualities
			Calorific Value (Btu/lb)	Moisture (%wt)	Ash (%wt)	Sulfur (%wt)
Mississippi Lignite Mining Company	Proven	15,700	5,120	43.3	14.7	0.6
Mississippi Lignite Mining Company	Probable	4,700	5,080	42.9	15.4	0.6
Mississippi Lignite Mining Company	Total	20,300	5,110	43.3	14.9	0.6

The Mineral Reserves as of December 31, 2024 presented in Table 2.3 below were determined to be the economically mineable portion of the measured and indicated Mineral Resources after the consideration of modifying factors related to the mining process. Inferred Mineral Resources were not considered for Mineral Reserves.

Lignite Coal	Reserve Classification	Tonnage(Kt)	Grades/Qualities
			Calorific Value (Btu/lb)	Moisture (%wt)	Ash (%wt)	Sulfur (%wt)
Mississippi Lignite Mining Company	Proven	18,200	5,090	43.3	14.9	0.6
Mississippi Lignite Mining Company	Probable	4,700	5,080	43.1	15.1	0.6
Mississippi Lignite Mining Company	Total	22,900	5,090	43.3	14.9	0.6

Note:

–Mineral Reserves Estimates have been prepared by a ~~qualified~~QP ~~person~~ employed by MLMC ~~as of December 31, 2024~~.

–Mineral Reserves have been demonstrated to be economic based on a positive cash flow

–Mineral Reserves are stated on a Run of Mine basis

–An economic cutoff in the Life of Mine plan averaged $34.41 per ton and was used to demonstrate coal reserves

–Recovery varies by coal seam and ranges from 67% to 100%

–Mineral Reserves use an economic cut-off of a maximum cumulative stripping ratio of 14:1. There are some instances where the stripping ratio for a single year could exceed 14:1, but the average for the entire area evaluated is less than 14:1.

–Historical coal recovery rates at Red Hills Mine have been applied to generate the Mineral Reserve tonnages.

–Mineral Reserves are estimated using Vulcan Software.

–Tonnages and qualities have been rounded to an accuracy level deemed appropriate by the QP. Summation errors due to rounding may exist.

Table 2.3 Mineral Reserves Summary as of December 31, ~~2024~~2025

Table 2.4 describes the difference between the Mineral Reserves and Mineral Resources reported as of December 31, ~~2023~~2024 and December 31, ~~2024~~2025.

Resource Classification	December 31, ~~2023~~2024 Tonnage (Kt)	December 31, ~~2024~~2025 Tonnage (Kt)	Percent Change
Measured	4,~~300~~400	4,400	2—%
Indicated	~~500~~400	400	~~(20)~~—%
Measured + Indicated	4,~~800~~700	4,700	~~(2)~~—%
Inferred	~~1,600~~100	100	~~(94)~~—%
Reserve Classification	December 31, ~~2023~~2024 Tonnage (Kt)	December 31, ~~2024~~2025 Tonnage (Kt)	Percent Change
Proven	1518,~~100~~200	1815,~~200~~700	21(14)%
Probable	74,~~400~~700	4,700	~~(36)~~—%
Proven + Probable	22,~~500~~900	2220,~~900~~300	2(11)%

Table 2.4. Net difference of reported Mineral Resources and Mineral Reserves from previous reporting period to current reporting period.

The Mineral Resources and Mineral Reserves as of December 31, ~~2024~~2025 reflect modifications from mining extraction of Mineral Reserves,. ~~acquisition~~No ofupdates ~~additional leased tracts which increased Mineral Reserves and an update~~ to ~~the resource model which allowed conversion of portions of~~ Mineral Resources towere ~~Mineral~~made ~~Reserves~~for 2025. ~~The~~Additionally, ~~update~~MLMC todelivered ~~the~~2.7 ~~resource~~million ~~model~~tons ~~added~~during ~~31 quality~~ 2025.

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core holes and 10 structural drill holes to the resource model. Mining extraction is occurring solely in Mine Area 3. Additionally, MLMC delivered 1.9 million tons during 2024.

2.2 Material Properties with no Mineral Resources or Mineral Reserves

The lignite coal tonnages at Coteau, Falkirk and Coyote Creek have not been classified as measured resources, indicated resources, or inferred resources as defined in Items 1300 through 1305 of Regulation S-K, and as a result, do not have any proven or probable reserves under such definition and are therefore classified as an Exploration Stage Property pursuant to Items 1300 through 1305 of Regulation S-K. Coteau, Falkirk and Coyote Creek will continue to be classified as exploration stage properties until such time as proven or probable mineral reserves have been established in accordance with subpart 1300 of Regulation S-K, even though they continue to deliver lignite to their respective customers.

Coteau, Coyote Creek and Falkirk each have only one customer for which they extract and deliver coal. These customers operate coal-fired electric generation power plants adjacent to each mine location (and in the case of Coteau, a synthetic natural gas and chemical/fertilizer production facility).

The sales price under the Coteau, Coyote Creek and Falkirk contracts are not market driven. Unlike traditional sales made based on market factors, under the provisions of the long-term mining agreements, the coal sales price at Coteau, Coyote Creek and Falkirk includes (i) all costs incurred to extract, process and deliver coal (i.e. the cost of production) and (ii) the agreed-upon profit per ton of coal or MMBtu unit delivered to the customer. Cost of production includes all the costs actually incurred in the operation of the mine including mining, processing and delivery of coal. Costs included within revenue include all production, transportation and maintenance costs including, without limitation, the following types of costs:

◦Labor, which include wages and all related payroll taxes, benefits and fringes, including welfare plans; group insurance, vacations and other comparable benefits of employees

◦Materials and supplies,

◦Tools,

◦Machinery and equipment not capitalized or leased,

◦Costs of acquiring interests in coal reserves and surface lands,

◦Rental of machinery and equipment,

◦Power costs,

◦Reasonable and necessary services by third parties

◦Insurance including worker’s compensation

◦Certain taxes, and

◦Cost of reclamation

The contractually-determined coal sales price includes reimbursement of all costs incurred and the agreed-upon profit. The agreed-upon profit adjusts based on changes in the level of established indices (e.g., CPI-U and/or PPI indices). The cost-plus nature of the contracts provide assurance that all costs incurred, including contemporaneous and final reclamation, will be reimbursed by the respective customer and negates any risk of loss which allows the mines to remain cash flow positive through the end of the contract terms. The coal sales price as well as profitability at Coteau, Falkirk and Coyote Creek are not subject to any change based on market factors. Profitability at these mines is affected by two factors: demand for coal (because this impacts units of agreed profit that are charged) and changes in the indices that determine coal sales price (because this adjusts the agreed-upon per unit profit). Under any scenario, Coteau, Coyote Creek and Falkirk will be cash flow positive as a result of the terms of the mining agreements.

Extraction of Coteau, Coyote Creek and Falkirk’s lignite tonnages is only economically viable as a result of the long-term mining agreements in place with each mine’s respective customer. The development of the Coteau, Coyote Creek and Falkirk mines was conducted in tandem with the development of the respective mine mouth power plants each serve. The power plants were designed to operate exclusively on the coal provided by the adjacent mines. No other market exists for the lignite at Coteau, Coyote Creek and Falkirk as the cost of transportation makes sales to any entity other than the current mine-mouth operator unprofitable.

35Coteau, Coyote Creek and Falkirk meet the definition of a 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 our financial statements. Instead, these contracts are accounted for as equity method investments. The income before income taxes

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Coteau, Coyote Creek and Falkirk meet the definition of a 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 our 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 Consolidated Statements of Operations, and our investment is reported on the line Investments in unconsolidated subsidiaries in the Consolidated Balance Sheets.

Coteau

The Freedom Mine, operated by Coteau, generally produces between 11.50 million and 13.50 million tons of lignite coal annually. The mine started delivering coal in 1983. All production from the mine is delivered to Dakota Coal Company, a wholly owned subsidiary of Basin Electric. Dakota Coal Company then sells the coal to the Synfuels Plant, Antelope Valley Station and Leland Olds Station, all of which are operated by affiliates of Basin Electric. The Synfuels Plant is a coal gasification plant that manufactures synthetic natural gas and produces fertilizers, solvents, phenol, carbon dioxide, and other chemical products for sale. In March 2025, the term of the existing lignite sales agreement was extended until 2032. The term may be extended for an additional five year period, or until 2037, at the option of Coteau.

The Freedom Mine is located approximately 90 miles northwest of Bismarck, North Dakota (Figure 2.2). The main entrance to the Freedom Mine is accessed by means of a paved road and is located on County Road 15. Coteau holds ~~355~~354 leases granting the right to extract approximately 3233,~~748~~451 acres of coal interests and the right to utilize approximately 2223,~~771~~085 acres of surface interests. In addition, Coteau owns in fee 33,888 acres of surface interests and 4,~~117~~237 acres of coal interests. Substantially all of the leases held by Coteau were acquired in the early 1970s and have been replaced with new leases or have lease terms for a period sufficient to meet Coteau’s contractual production requirements.

Figure 2.2 – Freedom Mine Location

The towns of Beulah, Hazen, and Stanton along with other smaller communities are within a 40-mile radius of the Freedom Mine and provide a vast supply of the employment base. Employees also come from the cities of Bismarck, Minot, and Dickinson, all of which are less than 100 miles away from the mine.

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The Freedom Mine sources power for mine office facilities and operations from Roughrider Electric Cooperative, and water for the mine office facilities from the Southwest Water Authority. Fuel for equipment is supplied by multiple local vendors. The Freedom Mine has, or is currently constructing, all supporting infrastructure for mining operations.

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The main entrance to the Freedom Mine is accessed by traveling north of Beulah on Highway 49 for one mile, then north on County Road 21 for two miles, then west on County Road 26 for three miles, and then north on County Road 15 for two miles as shown on Figure 2.2. Location of the Freedom Mine.

Travel to the Freedom Mine by air is possible by means of the Bismarck Municipal Airport, Bismarck, ND, which is approximately 90 miles southeast of the mine. From the airport, the mine is accessed by means of ground transportation by traveling west approximately 50 miles via Interstate 94, taking exit 110 and traveling north approximately 28 miles on ND Highway 49 to Beulah, ND, and so on as explained in the previous paragraph.

Travel to the Freedom Mine by rail is possible using the Amtrak Network, which runs through northern North Dakota mostly along the US Highway 2 corridor, and passes through the larger cities of Williston, Minot, Grand Forks, and Fargo, and smaller cities of Stanley, Rugby, and Devils Lake. From these locations, the mine can be accessed via ground transportation on Interstate 29 or Interstate 94 and various highways. The main highways are US Highway 2, US Highway 83, US Highway 85, US Highway 200, and US Highway 281.

North Dakota’s freight rail service is largely provided by Burlington Northern Santa Fe Railway and Canadian Pacific Railway.

The coal tonnages are located in Mercer County, North Dakota, starting approximately two miles north of Beulah, North Dakota. The formations of sedimentary origin were deposited in the Williston Basin, the dominant structural feature of western North Dakota. The center of the basin is located near the city of Williston, North Dakota, approximately 100 miles northwest of the Freedom Mine. The economically mineable coal occurs in the Sentinel Butte Formation, and is overlain by the Coleharbor Formation. The Coleharbor Formation unconformably overlies the Sentinel Butte Formation. It includes all of the unconsolidated sediments resulting from deposition during glacial and interglacial periods. Lithologic types include gravel, sand, silt, clay and till. The modified glacial channels are in-filled with gravels, sands, silts and clays overlain by till. The coarser gravel and sand beds are generally limited to near the bottom of the channel fill. The general stratigraphic sequence in the upland portions of the reserve area consists of till, silty sands and clayey silts.

Fill-in drilling programs are routinely conducted by Coteau for the purpose of refining guidance related to ongoing operations. It is common practice at the Freedom Mine to tighten the drilling density within the three to four-year block ahead of active operations to an average drill hole spacing of 660-feet. However, additional exploration may also be scheduled in areas farther out to increase confidence in future mine plan projections.

Coteau utilizes standard surface mining techniques to extract coal from the proposed permit area. Mining operations will typically occur in a sequence of seven events: suitable plant growth material removal, overburden removal, coal removal, overburden replacement, final grading, suitable plant growth material replacement, and revegetation.

The mine office facilities and original equipment fleets at the Freedom Mine were constructed, acquired, or purchased new during the development stage of the mine. The facilities and equipment are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, Coteau evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

The total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, ~~2024~~2025 is $~~162~~195.25 million.

The Freedom Mine currently has no significant encumbrances to the property. No NOVs have been issued at the Freedom Mine in the past three years. Coteau currently has all permits in place for the Freedom Mine to operate through 2031. Permit expansions required to extend the life of the mine through ~~2045~~2042 will be acquired as needed. No mineral processing occurs at the Freedom Mine.

Falkirk Mine

The Falkirk Mine generally produces between 7 million and 8 million tons of lignite coal annually. The mine started delivering coal in 1978 primarily for the Coal Creek Station, an electric power generating station. Coal Creek Station was owned by GRE until May 1, 2022 when it was purchased by Rainbow Energy. The initial production period is expected to run through May 1, 2032, but the coal sales agreement may be extended or terminated early under certain circumstances. In 2014, Falkirk began delivering coal to Spiritwood Station, another electric power generating station owned by GRE.

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~~2032~~The Falkirk Mine, ~~but~~operated by Falkirk, is located approximately 50 miles north of Bismarck, North Dakota on a paved access road off U.S. Highway 83 (Figure 2.3). Falkirk holds 341 leases granting the right to extract approximately 43,600 acres of coal ~~sales~~interests ~~agreement~~and ~~may~~the beright ~~extended~~to orutilize ~~terminated~~approximately ~~early~~22,475 ~~under~~acres ~~certain~~of ~~circumstances~~surface interests. In ~~2014~~addition, Falkirk ~~began~~owns ~~delivering~~in ~~coal~~fee to40,722 ~~Spiritwood~~acres ~~Station~~of surface interests and 2,148 ~~another~~acres ~~electric~~of ~~power~~coal ~~generating~~interests. ~~station~~Substantially ~~owned~~all of the leases held by ~~GRE~~Falkirk were acquired in the early 1970s with initial terms that have been further extended by the continuation of mining operations.

The Falkirk Mine, operated by Falkirk, is located approximately 50 miles north of Bismarck, North Dakota on a paved access road off U.S. Highway 83 (Figure 2.3). Falkirk holds 334 leases granting the right to extract approximately 43,015 acres of coal interests and the right to utilize approximately 22,964 acres of surface interests. In addition, Falkirk owns in fee 41,034 acres of surface interests and 1,788 acres of coal interests. Substantially all of the leases held by Falkirk were acquired in the early 1970s with initial terms that have been further extended by the continuation of mining operations.

The towns of Underwood and Washburn are located within ten miles of the mine, with other small communities also nearby. Numerous employees also reside in Bismarck and Mandan, a distance of about 50 miles.

The Falkirk Mine receives both power and water from Coal Creek Station. However, Falkirk’s East shift change building receives water from McLean-Sheridan Rural Water. Fuel for equipment is supplied by multiple local vendors including: Farstad Oil, Missouri Valley Petroleum, and Enerbase Cooperative Resources.

The main entrance to the Falkirk Mine is accessed by traveling north from Bismarck on State Highway 83 for approximately 50 miles, then going west on the access road, 1st Street SW located four miles south of Underwood. The mine office is located two miles to the west.

Travel to the Falkirk Mine by air is possible using the Bismarck Airport in Bismarck, ND, approximately 55 miles south of the mine, and then using ground transportation, traveling via US Highway 83.

The main railway systems near the Falkirk Mine are Canadian Pacific, BNSF, and Dakota Missouri Valley & Western (DMVW). DMVW crosses through the Falkirk Mine Reserve.

The coal tonnages are located in McLean County, North Dakota, from approximately nine miles northwest of the town of Washburn, North Dakota to four miles north of the town of Underwood, North Dakota. Structurally, the area is located on an intercratonic basin containing a thick sequence of sedimentary rocks. The economically mineable coal occurs in the Sentinel Butte Formation and the Bullion Creek Formation and are unconformably overlain by the Coleharbor Formation. The Sentinel Butte Formation conformably overlies the Bullion Creek Formation. The general stratigraphic sequence in the upland portions of the reserve area (Sentinel Butte Formation) consists of till, silty sands and clayey silts, main hagel lignite bed, silty clay, lower lignite of the hagel lignite interval and silty clays. Beneath the Tavis Creek, there is a repeating sequence of silty to sand clays with generally thin lignite beds.

Operationally, overburden and interburden removal are accomplished using scrapers, dozers, front end loaders, truck shovel fleets, and draglines. Lignite is mined with front end loaders or hydraulic backhoes, and loaded into haul trucks to transport to the stockpile or directly to the customer via truck dumps and conveyors.

Fill-in drilling programs are routinely conducted by Falkirk for the purpose of refining guidance related to ongoing operations. It is common practice at the Falkirk Mine to tighten the drilling density within the three to four-year block ahead of active operations to an average drill hole spacing of 1320-feet. However, additional exploration may also be scheduled in areas farther out to increase confidence in future mine plan projections.

The mine office facilities and original equipment fleets at the Falkirk Mine were constructed, acquired, or purchased new during the development stage of the mine. The facilities and equipment are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, Falkirk evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

The total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, ~~2024~~2025 is $5870.7 million.

The Falkirk Mine currently has no significant encumbrances to the property. No Notice of Violations (NOVs) have been issued at the Falkirk Mine in the past three years. There are no outstanding permits related to the LOM plan awaiting regulatory approval. The Falkirk Mining Company currently has all permits in place to operate and adhere to the current mine plan. No mineral processing occurs at the Falkirk Mine.

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Figure 2.3 – Falkirk Mine Location

Coyote Creek

The Coyote Creek Mine generally produces between 1.5 million and 2.0 million tons of lignite annually. The mine began delivering coal in 2016 to the Coyote Station owned by Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Company and Northwestern Corporation. The term of the existing lignite sales agreement terminates in 2040.

The Coyote Creek Mine is located approximately 70 miles northwest of Bismarck, North Dakota (Figure 2.4). The main entrance to the Coyote Creek Mine is accessed by means of a four-mile paved road extending west off of State Highway 49. Coyote Creek holds a sublease to 86 leases granting the right to mine approximately 8,129 acres of coal interests and the right to utilize approximately 15,168 acres of surface interests. In addition, Coyote Creek Mine owns in fee 160 acres of surface interests and has four easements to conduct coal mining operations on approximately 352 acres.

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Figure 2.4 – Coyote Creek Mine Location

The towns of Beulah, Hazen, and Stanton along with other smaller communities are within a 40-mile radius of the Coyote Creek Mine and provide a vast supply and employment base. A vast supply and employment base also come from some of the major cities of Bismarck, Minot, and Dickinson, all of which are less than 100 miles away from the mine.

The Coyote Creek Mine sources power for mine office facilities and operations from Roughrider Electric Cooperative and Montana-Dakota Utilities Co., and water for the mine office facilities from the Southwest Water Authority. Fuel for equipment is supplied by multiple local vendors. The Coyote Creek Mine has all supporting infrastructure for mining operations.

The main entrance to the mine will be accessed by traveling south of Beulah on Highway 49 for five miles, then west on County Road 25 for four miles. The general location of the Coyote Creek Mine is shown in Figure 1.0 Location of Coyote Creek Mine.

Travel to the Coyote Creek Mine by air is possible using the Bismarck Municipal Airport, Bismarck, ND, approximately 75 miles southeast of the mine. From the airport, the mine is accessed using ground transportation by traveling west approximately 50 miles via Interstate 94, taking exit 110 and traveling north approximately 21 miles on ND Highway 49 to County Road 25, then west for four miles on County Road 25.

Travel to the Coyote Creek Mine by rail is possible using the Amtrak Network, which runs through northern North Dakota mostly along the US Highway 2 corridor, and passes through the larger cities of Williston, Minot, Grand Forks, and Fargo, and smaller cities of Stanley, Rugby, and Devils Lake. From these locations, the mine can be accessed via ground transportation on Interstate 29 or Interstate 94 and various highways. The main highways are US Highway 2, US Highway 83, US Highway 85, US Highway 200, and US Highway 281.

North Dakota’s freight rail service is largely provided by Burlington Northern Santa Fe Railway and Canadian Pacific Railway.

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The coal tonnages are located in Mercer County, North Dakota, starting approximately six miles southwest of Beulah, North Dakota. The formations of sedimentary origin were deposited in the Williston Basin, the dominant structural feature of western North Dakota. The center of the basin is located near the city of Williston, North Dakota, approximately 110 miles northwest of the Coyote Creek Mine. The economically mineable coal occurs in the Sentinel Butte Formation, and is overlain by the Coleharbor Formation. The Coleharbor Formation unconformably overlies the Sentinel Butte Formation. It includes all of the unconsolidated sediments resulting from deposition during glacial and interglacial periods. Lithologic types include gravel, sand silt, clay and till. The modified glacial channels are in-filled with gravels, sands, silts and clays overlain by till. The coarser gravel and sand beds are generally limited to near the bottom of the channel fill. The general stratigraphic sequence in the upland portions of the reserve area consists of till, silty sands and clayey silts.

Fill-in drilling programs are routinely conducted by Coyote Creek for the purpose of refining guidance related to ongoing operations. It is common practice at the Coyote Creek Mine to tighten the drilling density within the three to four-year block ahead of active operations to an average drill hole spacing of 660-feet. However, additional exploration may also be scheduled in areas farther out to increase confidence in future mine plan projections.

Operationally, overburden removal is accomplished using scrapers, dozers, front end loaders, excavators, truck fleets, and a dragline. Lignite is mined with front end loaders, and loaded into haul trucks to transport to the coal stockpile.

The mine office facilities and original equipment fleets at the Coyote Creek Mine were constructed, acquired, or purchased during the development stage of the mine. The facilities and equipment are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, Coyote Creek evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

The total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, ~~2024~~2025 is $~~105~~97.90 million.

The Coyote Creek Mine currently has no significant encumbrances to the property. No NOVs have been issued at the Coyote Creek Mine in the past three years. There are no outstanding permits related to the LOM plan awaiting regulatory approval. Coyote currently has all permits in place for the Coyote Creek Mine to operate and adhere to a mine plan projected through 2040. No mineral processing occurs at the Coyote Creek Mine.

3.0 Internal Control Disclosure Over Mineral Resources and Reserves

The modeling and analysis of our resources and reserves has been developed by our mine personnel and reviewed by several levels of internal management, including the QPs. The development of such resources and reserves estimates, including related assumptions, was a collaborative effort between the QPs and Company staff. This section summarizes the internal control considerations for our development of estimations, including assumptions, used in resource and reserve analysis and modeling.

When determining resources and reserves, as well as the differences between resources and reserves, management developed specific criteria, each of which must be met to qualify as a resource or reserve, respectively. These criteria, such as demonstration of economic viability, points of reference and grade, are specific and attainable. The QPs and our management team agree on the reasonableness of the criteria for the purposes of estimating resources and reserves. Calculations using these criteria are reviewed and validated by the QPs.

Estimations and assumptions were developed independently for each significant mineral location. All estimates require a combination of historical data and key assumptions and parameters. When possible, resources and data from generally accepted industry sources were used to develop these estimations. Review teams were created by utilizing subject matter experts from across all of NACCO to review the cost assumptions and estimations used as the basis of the classification of mineral resources and reserves.

Geological modeling and mine planning efforts serve as a base assumption for resource estimates at MLMC. These outputs have been prepared and reviewed by Company personnel. Mine planning decisions are determined and agreed upon by our management. Management adjusts forward-looking models by reference to historic mining results, including by reviewing actual versus predicted levels of production from the mineral deposit, and if necessary, re-evaluating mining methodologies if production outcomes were not realized as predicted. Ongoing mining of the mineral deposit, coupled with product quality validation pursuant to our and our customer expectations, provides further empirical evidence as to the homogeneity, continuity and characteristics of the deposit. Geologic modeling assumptions are evaluated to historic mining results and are adjusted if necessary to better reflect actual mining results. Ongoing quality validation of production also provides a means to monitor for

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any potential changes in quality. Also, ongoing monitoring of ground conditions within the mine, surveying for evidence of subsidence and other visible signs of deterioration that may signal the need to re-evaluate rock mechanics and structure of the mine ultimately inform extraction ratios and mine design, which underpin mineral reserve estimates.

Management also assesses risks inherent in mineral resource and reserve estimates, such as the accuracy of geophysical data that is used to support mine planning, changes in QPs, identifying hazards and informing operations of the presence of mineable deposits. Also, management is aware of risks associated with potential gaps in assessing the completeness of mineral extraction licenses, entitlements or rights, or changes in laws or regulations that could directly impact the ability to assess mineral resources and reserves or impact production levels. Risks inherent in overestimated reserves can impact financial performance when revealed, such as changes in amortizations that are based on life of mine estimates.

4.0 Customer-owned Properties

South Hallsville No. 1 Mine — The Sabine Mining Company

The Sabine Mining Company (Sabine) operated 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 commenced final reclamation on April 1, 2023. Funding for mine reclamation is the responsibility of SWEPCO, and Sabine receives compensation for providing mine reclamation services. Sabine will provide mine reclamation services through September 30, ~~2026. As of October 1, 2026, SWEPCO has an obligation to acquire all of the capital stock of Sabine and complete the remaining mine reclamation.~~

2026. As of October 1, 2026, SWEPCO is obligated to acquire all of the capital stock of Sabine and complete the remaining

mine reclamation.

5.0 Facilities and Equipment

The facilities and equipment for each of the coal mines are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, the mines evaluate what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment, and proceed with that replacement. The mining method and total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2025 is set forth in the chart below:

Location

Mining Method

Total Historical Cost of MineProperty, Plant and Equipment, Net of Applicable AccumulatedAmortization, Depreciation and Impairment

Unconsolidated Mining Operations

(in millions)

Freedom Mine — The Coteau Properties Company

Dragline operation with 3 draglines

~~162~~195.25

Falkirk Mine — The Falkirk Mining Company

Dragline operation with 43 draglines

5870.7

Coyote Creek Mine — Coyote Creek Mining Company, LLC

Dragline operation with 1 dragline

~~105~~97.90

Consolidated Mining Operations

Red Hills Mine — Mississippi Lignite Mining Company

Dragline operation with 1 dragline

5254.54

~~NAMining~~Contract Mining Segment - Operations

~~NAMining~~Contract Mining provides contract mining services for independently owned mines and quarries, primarily operating and maintaining draglines at limestone quarries and utilizing other mining equipment at sand and gravel quarries. At December 31, ~~2024~~2025, ~~NAMining~~Contract Mining operated 3134 draglines and other equipment at 23 quarries. Of the 3134 draglines, 78 are owned by us and 2426 are owned by customers. At December 31, ~~2024~~2025, ~~NAMining~~Contract Mining had $7296.75 million in property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment.

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The mining process at the limestone mines involves excavating limestone from a water-filled quarry utilizing draglines. The excavated limestone is transported and processed by the customer. The following ~~mines~~locations were operational during ~~2024~~2025:

Location Name

Aggregate

Location

State

Customer

Year NACCO Started Operations

White Rock — North

Limestone

Miami

WRQ

1995

Krome

Limestone

Miami

Cemex

2003

Alico

Limestone

Ft. Myers

Cemex

2004

FEC

Limestone

Miami

Cemex

2005

SCL

Limestone

Miami

Cemex

2006

Central State Aggregates

Limestone

Zephyrhills

McDonald Group

2016

Mid Coast Aggregates

Limestone

Sumter County

McDonald Group

2016

West Florida Aggregates

Limestone

Hernando County

McDonald Group

2016

St. Catherine

Limestone

Sumter County

Cemex

2016

Center Hill

Limestone

Sumter County

Cemex

2016

Inglis

Limestone

Crystal River

Cemex

2016

Titan Corkscrew

Limestone

Ft. Myers

Titan America

2017

Palm Beach Aggregates

Limestone

Loxahatchee

Palm Beach Aggregates

2017

Perry

Limestone

Lamont

Martin Marietta

2018

SDI Aggregates

Limestone

Florida City

Martin Marietta

2018

Queenfield

Sand and gravel

King William County

Holcim Group

2018

Newberry

Limestone

Alachua County

Summit Materials/Quikrete

2019

Seven Diamonds

Limestone

Pasco County

Summit Materials/Quikrete

2021

Little River

Sand and gravel

Ashdown

Heidelberg Materials

2021

Rosser

Sand and gravel

Ennis

Heidelberg Materials

2021

Rosser (a)

Sand and gravel

Ennis

Heidelberg Materials

2021

Brooksville Cement Plant

Limestone

Brooksville

Cemex

2021

Ash Grove

Limestone

Louisville

Ash Grove, A CRH Company

2022

MDL(a)

Phosphate

Polk County

Mineral Development, LLC

2024

Fort Myers Quarry

Sand and gravel

Ft. Myers

Martin Marietta

2025

19th Ave Quarry

Sand and gravel

Phoenix

Cemex

2025

(a) The ~~MDL~~Contract ~~quarry~~Mining ~~was~~segment ~~idled~~ceased operating at the Rosser location during ~~2024~~2025. ~~NAMining~~The Contract Mining segment mined de0.3 ~~minimis~~million ~~amounts~~and 1.2 million tons of sand and gravel at ~~this~~the Rosser location during 2025 and 2024, respectively.

~~NAMining~~Contract Mining's customers control all of the limestone and sand reserves within their respective mines. ~~NAMining~~Contract Mining has no title, claim, lease or option to acquire any of the reserves at any of the mines where it provides services.

Access to the White Rock mine is by means of a paved road from 122nd Avenue.

Access to the Krome mine is by means of a paved road from Krome Avenue.

Access to the Alico mine is by means of a paved road from Alico Road.

Access to the FEC mine is by means of a paved road from NW 118th Avenue.

Access to the SCL mine is by means of a paved road from NW 137th Avenue.

Access to the Central State Aggregates mine is by means of a paved road from Yonkers Boulevard.

Access to the Mid Coast Aggregates mine is by means of a paved road from State Road 50.

Access to the West Florida Aggregates mine is by means of a paved road from Cortez Boulevard.

Access to the St. Catherine mine is by means of a paved road from County Road 673.

Access to the Center Hill mine is by means of a paved road from West Kings Highway.

Access to the Inglis mine is by means of a paved road from Highway 19 South.

Access to the Titan Corkscrew mine is by means of a paved road from Corkscrew Road.

~~Access to the Palm Beach Aggregates mine is by means of a paved road from State Road 80.~~39

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Access to the Palm Beach Aggregates mine is by means of a paved road from State Road 80.

Access to the Perry mine is by means of paved road from Nutall Rise Road.

Access to the SDI Aggregates mine is by means of paved road from SW 167th AVE.

Access to the Queenfield Mine is by means of paved road from Dabney's Mill Road (SR 604).

Access to the Newberry mine is by means of paved road from NW County Road 235 (CR 235).

Access to the Seven Diamonds mine is by means of a paved road from US-41 S/Broad St.

Access to the Little River mine is by means of an unpaved road from Little River 60.

Access to the Rosser mine is by means of a paved road from TX-34 S.

Access to Brooksville Cement plant is by means of a paved road from Cement Plant Road.

Access to Ash Grove Louisville Quarry is by means of a paved road from HWY 50.

Access to ~~MDL~~the Fort Myers Quarry is by means of ~~Noralyn~~a ~~Mine~~paved road from Alico Road.

~~Minerals~~Access ~~Management~~to -the ~~Operations~~19th Ave Quarry is by means of paved road from 27th Ave.

Minerals and Royalties - Operations

As an owner of royalty and mineral interests, our access to information concerning activity and operations of our royalty and mineral interests is limited. We do not have information that would be available to a company with oil and natural gas operations because detailed information is not generally available to owners of royalty and mineral interests. Consequently, the exact number of wells producing from or drilling on our mineral interests at a given point in time is not determinable. The following table sets forth our estimate of the number of gross and net productive wells:

December 31, 2024

December 31, 2023

December 31, 2025

December 31, 2024

Gross

Net

Gross

Net

Oil

1,~~295~~663

4.37

1,~~646~~295

64.63

Natural Gas

~~922~~851

1819.52

~~246~~922

1318.5

Total

2,~~217~~514

2223.89

12,~~892~~217

2022.18

Gross wells are the total wells in which an interest is owned.

Net wells are calculated based on our net royalty interest, factoring in both ownership percentage of gross wells and royalty rate.

The majority of our producing mineral and royalty interest acreage now, or in the future, can be pooled with third-party acreage to form pooled units. Pooling proportionately reduces our royalty interest in wells drilled in a pooled unit, and it proportionately increases the number of wells in which we have such reduced royalty interest.

The following table includes our estimate of acreage for oil and gas mineral interests, NPRIs, and ORRIs:

December 31, 2024

December 31, 2023

December 31, 2025

December 31, 2024

Gross Acres

Net Royalty Acres

Gross Acres

Net Royalty Acres

Appalachia

34,661

36,199

34,661

36,199

Gulf Coast

2728,~~932~~012

20,~~105~~196

27,932

20,105

Permian

~~121~~130,~~437~~902

4,~~568~~973

~~120~~121,~~636~~437

4,~~556~~568

Rockies

13,233

659

~~326~~13,233

72659

Williston

1,194

2,388

1,194

2,388

Total

~~198~~208,~~457~~002

6364,~~919~~415

~~184~~198,~~749~~457

63,~~320~~919

We may own more than one type of interest in the same tract of land, but the overlap is not significant. Net royalty acres are calculated based on our ownership and royalty rate, normalized to a standard 1/8th royalty lease, and assumes a 1/4th royalty rate for unleased acres.

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The following table includes our estimate of developed and undeveloped acreage based on the gross acres in a basin or region and includes mineral interests, NPRIs, and ORRIs:

	December 31, 2024			December 31, 2023
	December 31, 2025			December 31, 2024
	Developed Acreage	Undeveloped Acreage	Gross Acreage	Developed Acreage	Undeveloped Acreage	Gross Acreage
Appalachia	32,156	2,505	34,661	32,156	2,505	34,661
Gulf Coast	22,~~191~~271	5,741	2728,~~932~~012	22,191	5,741	27,932
Permian	~~118~~125,~~021~~887	35,~~416~~015	~~121~~130,~~437~~902	~~117~~118,~~220~~021	3,416	~~120~~121,~~636~~437
Rockies	7,696	5,537	13,233	~~326~~7,696	—5,537	~~326~~13,233
Williston	—	1,194	1,194	—	1,194	1,194
Total	~~180~~188,~~064~~010	1819,~~393~~992	~~198~~208,~~457~~002	~~171~~180,~~893~~064	1218,~~856~~393	~~184~~198,~~749~~457

Undeveloped acres are either unleased and open or are leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

Production and Price History

The following table sets forth the estimated oil and natural gas production data related to our mineral and royalty interests as well as certain price and cost information for the years ended December 31:

	2024 (4)		2023 (4)
	2025 (4)		2024 (4)
Production data:
Oil (bbl) (1)	~~149~~112,~~529~~308		98149,~~553~~529
NGL (bbl) (1)	6572,~~053~~430		5665,~~768~~053
Residue gas (Mcf) (2)	87,~~482~~957,~~414~~946		78,~~601~~482,~~521~~414
Total BOE (3)	1,~~628~~511,~~318~~063		1,~~422~~628,~~241~~318
Average realized prices:
Oil (bbl) (1)	$	7864.4551	$	7278.1945
NGL (bbl) (1)	$	2223.9421	$	2322.3394
Residue gas (Mcf) (2)	$	23.0813	$	2.3708
Average unit cost
BOE (3)	$	2.7958	$	32.3279

(1) Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

(2) Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

(3) BOE. Barrel of Oil Equivalent, a conversion factor of 6 MCF of gas was used for 1 equivalent bbl of oil.

(4) As an owner of mineral and royalty interests, our access to information concerning activity and operations of our royalty and mineral interests is limited. As a result, we estimated the last two months of ~~2024~~2025 and ~~2023~~2024 production and pricing data using projections based on decline rates of wells and prior expense information.

Evaluation and Review of Reserves

The reserve estimates as of December 31, ~~2024~~2025 were prepared by Haas & Cobb Petroleum Consultants (Haas & Cobb). Haas & Cobb is an independent, third-party, petroleum engineering firm that meets industry-standards for qualifications, independence, objectivity and confidentiality. The primary technical person, Franklin Stagg, responsible for preparing the Reserve Report, Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at Haas & Cobb since 2016 and has over 910 years of industry experience. Haas & Cobb does not own an interest in NACCO or any of our properties, nor is it employed on a contingent basis. A copy of Haas & Cobb's estimated proved reserve report as of December 31, ~~2024~~2025 is incorporated by reference herein to Exhibit 99.1 to this Form 10-K.

The properties evaluated for proved reserves are located in Alabama, Louisiana, New Mexico, Ohio, Pennsylvania, Texas, Utah and Wyoming and represent all of our oil and gas reserves. A reserves audit is not the same as a financial audit. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of

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engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on several variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs.

The reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry. Decline curve analysis was used to estimate the remaining reserves of pressure depletion reservoirs with enough historical production data to establish decline trends. Reservoirs under non-pressure depletion drive mechanisms and non-producing reserves were estimated by volumetric analysis, research of analogous reservoirs, or a combination of both. Reserves have been estimated using deterministic and probabilistic methods. The appropriate methodology was used, as deemed necessary, to estimate reserves in conformance with SEC regulations. The maximum remaining reserves life assigned to wells included in this report is 50 years.

Total net proved reserves are defined as our natural gas and hydrocarbon liquid reserves after deducting all royalties, overriding royalties, and reversionary interests owned by outside parties that become effective upon payout of specified monetary balances. All reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry and conform to guidelines developed and adopted by the SEC.

Technologies Used in Reserve Estimation

The SEC’s reserves rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. The term reasonable certainty implies a high degree of confidence that the quantities of oil, natural gas and/or NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, we employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of our reserves is a function of:

•the quality and quantity of available data and the engineering and geological interpretation of that data;

•estimates regarding the amount and timing of future operating costs, development costs and workovers, all of which may vary considerably from actual results;

•future prices of oil, natural gas and NGLs, which may vary considerably from those estimated; and

•the judgment of the persons preparing the estimates.

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

Net reserves as of December 31, 2024

Net reserves as of December 31, 2023

Net reserves as of December 31, 2025

Net reserves as of December 31, 2024

Oil (bbl) (1)

NGL (bbl) (1)

Residue gas (Mcf) (2)

Oil (bbl) (1)

NGL (bbl) (1)

Residue gas (Mcf) (2)

Proved developed

~~620~~590,~~790~~134

~~443~~567,~~650~~276

27,~~491~~255,~~840~~664

~~656~~620,~~370~~790

~~380~~443,650

2327,~~596~~491,~~110~~840

Proved undeveloped

7483,~~400~~559

3017,~~280~~528

~~135~~251,~~830~~964

974,~~020~~400

330,~~720~~280

26135,~~420~~830

Total

~~695~~673,~~190~~693

~~473~~584,~~930~~804

27,~~627~~507,~~670~~628

~~665~~695,~~390~~190

~~384~~473,~~370~~930

2327,~~622~~627,~~530~~670

(1) Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

(2) Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

We do not currently have any material investments under which it would be required to bear the cost of exploration, production or development. We did not make capital expenditures to convert proved undeveloped reserves from undeveloped to developed.

Internal Control Disclosure

Our internal staff works closely with Haas & Cobb to ensure the integrity, accuracy and timeliness of the data used to calculate proved reserves relating to NACCO's assets. Internal technical team members met with independent reserve engineers periodically during the period covered by the reserves report to discuss the assumptions and methods used in the proved reserve estimation process.

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The preparation of our proved reserve estimates is completed in accordance with internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

•Review and verification of historical production data, which data is based on actual production as reported by third-party producers who lease our royalty and mineral interests;

•Preparation of reserve estimates by Haas & Cobb under the direct supervision of internal staff; and

•Verification of property ownership by our land department.

The Minerals ~~Management~~and Royalties Segment’s Vice President of Engineering and Finance is the technical person primarily responsible for overseeing the preparation of the internal reserve estimates and for coordinating with Haas & Cobb in the preparation of the third-party reserve report. The Vice President of Engineering and Finance has over 15 years of industry experience with positions of increasing responsibility and reports directly to the President of Catapult Mineral Partners, our business unit focused on managing and expanding our portfolio of oil and gas mineral and royalty interests.

Estimated Proved Reserves

The following table summarizes changes in proved reserves during the year ended December 31, ~~2024~~2025:

	Estimated Proved Reserves
	Oil (bbl) (1)	NGL (bbl) (1)	Residue gas (Mcf) (2)
December 31, 2023	665,390	384,370	23,622,530
Purchases	14,005	1,233	29,268
Extensions and discoveries	236,491	85,087	7,040,710
Revisions of previous estimates (3)	(105,479)	63,441	(498,627)
Production	(32,077)	(15,687)	(1,843,911)
Other	(83,140)	(44,514)	(722,300)
December 31, 2024	695,190	473,930	27,627,670
Purchases	31,899	29,325	117,191
Extensions and discoveries	140,256	46,110	3,679,131
Revisions of previous estimates (3)	(217,574)	21,880	(5,460,266)
Production	(32,077)	(15,687)	(1,843,911)
Other	55,999	29,246	3,387,813
December 31, 2025	673,693	584,804	27,507,628

Estimated Proved Undeveloped Reserves (PUDs)

The following table summarizes changes in PUDs during the year ended December 31, ~~2024~~2025:

	Estimated Proved Undeveloped Reserves
	Oil (bbl) (1)	NGL (bbl) (1)	Residue gas (Mcf) (2)
December 31, 2023	9,020	3,720	26,420
Purchases	2,208	38	5,237
Extensions and discoveries	69,716	27,902	126,724
Conversions	(3,322)	(1,914)	(10,017)
Revisions of previous estimates (3)	(3,222)	534	(12,534)
December 31, 2024	74,400	30,280	135,830
Extensions and discoveries	54,481	7,547	172,125
Revisions of previous estimates (3)	(45,322)	(20,299)	(55,991)
December 31, 2025	83,559	17,528	251,964

(1) Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

(2) Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

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

As an owner of mineral and royalty interests, we generally do not have evidence or approval of operators’ development plans. As a result, proved undeveloped reserve estimates are limited to those relatively few locations for which drilling permits have been publicly filed. As of December 31, ~~2024~~2025, PUD reserves consists of 89126 wells in various stages of drilling or completions. As of December 31, ~~2024~~2025, ~~less~~approximately ~~than 1~~2% of our total proved reserves were classified as PUDs.

Headquarter locations

NACCO leases office space in Highland Hills, Ohio, a suburb of Cleveland, Ohio, which serves as our corporate headquarters.

Utility Coal Mining and Minerals ~~Management~~and Royalties lease corporate headquarters office space in Plano, Texas.

47Contract Mining leases office and warehouse space in Medley, Florida.

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NAMining leases office and warehouse space in Medley, Florida.

Item 3. LEGAL PROCEEDINGS

We are not a party to any material legal proceeding other than ordinary routine litigation incidental to our respective business.

Item 4. MINE SAFETY DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of The Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 filed with this Form 10-K.

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PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

NACCO's Class A common stock is traded on the New York Stock Exchange under the ticker symbol NC. Because of transfer restrictions, no trading market has developed, or is expected to develop, for our Class B common stock. The Class B common stock is convertible into Class A common stock on a one-for-one basis.

At December 31, ~~2024~~2025, there were ~~648~~631 Class A common stockholders of record and ~~110~~104 Class B common stockholders of record.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Issuer Purchases of Equity Securities (1)
Issuer Purchases of Equity Securities (1) (2)
Period	(a)Total Number of Shares Purchased	(b)Average Price Paid per Share		(c)Total Number of Shares Purchased as Part of the Publicly Announced Program	(d)Maximum Number of Shares (or Approximate Dollar Value) that May Yet Be Purchased Under the Program (1)
October 1 to 31, 2024	—	$	—	—	$	8,909,786
October 1 to 31, 2025	—	$	—	—	$	7,846,258
November 1 to 30, 2024	—	$	—	—	$	8,909,786
November 1 to 30, 2025	—	$	—	—	$	20,000,000
December 1 to 31, 2024	12,610	$	29.20	12,610	$	8,541,574
December 1 to 31, 2025	39,356	$	46.70	39,356	$	18,162,075
Total	1239,~~610~~356	$	2946.2070	1239,~~610~~356	$	818,~~541~~162,~~574~~075

(1) On November 718, ~~2023~~2025, our Board of Directors approved a stock purchase program providing for the purchase of up to $20.0 million of our outstanding Class A common stock through December 31, ~~2025~~2027. See Note 12 to the Consolidated Financial Statements in this Form 10-K for a discussion of our stock repurchase programs.

Item 6. [RESERVED]

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

OVERVIEW

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 subsidiary, NACCO Natural Resources Corporation® (NACCO Natural Resources, and with NACCO collectively, the Company, we, our or us). NACCO Natural Resources brings natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through our robust portfolio of businesses. We operate under three reportable business segments: Utility Coal Mining, ~~North~~Contract ~~American~~ Mining® ~~(NAMining)~~ and Minerals ~~Management~~and Royalties. The Utility Coal Mining segment, ~~operates~~operated by North American Coal®, manages surface coal mines that are exclusive, long-term fuel providers for power generation companies. The ~~NAMining~~Contract Mining segment, isoperated aby ~~trusted~~North ~~mining~~American ~~partner~~Mining®, ~~for~~is ~~producers~~a leading provider of ~~aggregates,~~a ~~activated~~broad ~~carbon,~~range ~~lithium~~of ~~and~~specialized, ~~other~~long-term ~~industrial~~contract ~~minerals~~mining services. The Minerals ~~Management~~and Royalties 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~~royalty ~~mitigation~~interests ~~solutions as well as comprehensive reclamation~~ and ~~restoration~~other ~~construction~~related ~~services~~investments. ~~In addition, ReGen Resources is pursuing opportunities to develop new power generation resources.~~

~~All~~We ~~financial~~also ~~statement~~have ~~line~~ items ~~below~~not directly attributable to an operating ~~profit~~segment. ~~(loss)~~These ~~(other~~items ~~income~~primarily include administrative costs related to public company reporting requirements, including ~~interest~~management ~~expense~~ and ~~interest~~board ~~income~~compensation, the ~~provision~~financial ~~(benefit)~~results ~~for~~of ~~income~~developing ~~taxes~~businesses and ~~net~~Bellaire ~~income~~Corporation (~~loss~~Bellaire)). ~~are~~Bellaire ~~presented~~manages ~~and~~long-term ~~discussed~~liabilities ~~within~~related ~~this~~to ~~Form~~former ~~10-K~~Eastern onU.S. aunderground ~~consolidated~~mining ~~basis~~activities.

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

See Item 1. Business beginning on page 1 in this Form 10-K for further discussion of NACCO's subsidiaries. Additional information relating to financial and operating data on a segment basis (including unallocated items) is set forth in Note 15 to the Consolidated Financial Statements contained in this Form 10-K.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities (if any). On an ongoing basis, we evaluate our estimates based on historical experience, actuarial valuations and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from those estimates.

We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of the consolidated financial statements.

Revenue recognition: Revenues are recognized when control of the promised goods or services is transferred to our customers, in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. We account for revenue in accordance with Accounting Standards Codification (ASC) Topic 606, Revenue from Contracts with Customers. See Note 3 to the Consolidated Financial Statements in this Form 10-K for further discussion of our revenue recognition.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

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

Identifying and assessing whether impairment indicators exist, or if events or changes in circumstances have occurred, including assumptions about future power plant dispatch levels, changes in future sales price, operating costs and other factors that impact anticipated revenue and customer demand, requires significant judgment. We determined that indicators of impairment existed at MLMC during the fourth quarter of 2023 and, as a result, MLMC's long-lived assets were reviewed for impairment. We assessed the recoverability of the MLMC asset group and determined that the assets were not fully recoverable when compared to the remaining future undiscounted cash flows from these assets. As a result, we estimated the fair value of the asset group which resulted in a non-cash, long-lived asset impairment charge of $65.9 million in 2023.

See Note 9 to the Consolidated Financial Statements in this Form 10-K for further discussion of our impairment analysis.

Income taxes: We file income tax returns in the U.S. federal jurisdiction, and in various state and foreign jurisdictions. Tax law requires certain items to be included in the tax return at different times than the items are reflected in the financial statements. Some of these differences are permanent, such as the benefit associated with percentage depletion (tax deductions for depletion that may exceed the tax basis in the mineral reserve) and expenses that are not deductible for tax purposes, and some differences are temporary, reversing over time, such as depreciation expense. These temporary differences create deferred tax assets and liabilities using currently enacted tax rates. The objective of accounting for income taxes is to recognize the amount of taxes payable or refundable for the current year, and deferred tax liabilities and assets for the future tax consequences of events that have been recognized in the financial statements or tax returns. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the provision for income taxes in the period that includes the enactment date. Management is required to estimate the timing of the recognition of deferred tax assets and liabilities, make assumptions about the future deductibility of deferred tax assets and assess deferred tax liabilities based on enacted laws and tax rates for the appropriate tax jurisdictions to determine the amount of such deferred tax assets and liabilities. Changes in the calculated deferred tax assets and liabilities may occur in certain circumstances, including statutory income tax rate changes, statutory tax law changes, or changes in the structure or tax status.

Our tax assets, liabilities, and tax expense are supported by historical earnings and losses and our best estimates and assumptions of future earnings. We assess whether a valuation allowance should be established against our deferred tax assets based on consideration of all available evidence, both positive and negative, using a more likely than not standard. This assessment considers, among other matters, scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. The assumptions about future taxable income require significant judgment and are consistent with the plans and estimates we use to manage the underlying businesses. When we determine, based on all available evidence, that it is more likely than not that deferred tax assets will not be realized, a valuation allowance is established.

Since significant judgment is required to assess the future tax consequences of events that have been recognized in our financial statements or tax returns, the ultimate resolution of these events could result in adjustments to our financial statements and such adjustments could be material. We believe the current assumptions, judgments and other considerations used to estimate the current year accrued and deferred tax positions are appropriate. If the actual outcome of future tax consequences differs from these estimates and assumptions, due to changes or future events, the resulting change to the provision for income taxes could have a material impact on our results of operations and financial position. Since 2021, we have participated in a voluntary program with the IRS called Compliance Assurance Process (CAP). The objective of CAP is to contemporaneously work with the IRS to achieve federal tax compliance and resolve all or most issues prior to the filing of the tax return.

Since 2021, we have participated in a voluntary program with the IRS called Compliance Assurance Process (CAP). The objective of CAP is to contemporaneously work with the IRS to achieve federal tax compliance and resolve all or most issues prior to the filing of the tax return.

See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of our income taxes.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

CONSOLIDATED FINANCIAL SUMMARY

Our results of operations were as follows for the years ended December 31:

	2024			2023
	2025			2024
Revenues:
Coal Mining	$	68,611		$	85,415
Utility Coal Mining	$	88,188		$	68,611
NAMining	119,600			90,532
Contract Mining	140,013			119,600
Minerals Management	34,579			32,985
Minerals and Royalties	37,630			34,579
Unallocated Items	1715,~~707~~080			817,~~459~~707
Eliminations	(23,~~789~~713)			(2,~~597~~789)
Total revenue	$	~~237~~277,~~708~~198		$	~~214~~237,~~794~~708
Operating profit (loss):
Coal Mining	$	24,311		$	(71,342)
Utility Coal Mining	$	17,155		$	24,311
NAMining	5,772			3,348
Contract Mining	5,767			5,772
Minerals Management	28,927			19,418
Minerals and Royalties	29,108			28,927
Unallocated Items	(2329,~~317~~962)			(2123,~~461~~317)
Eliminations	12(87)			~~(100)~~12
Total operating profit (loss)	$	35,705		$	(70,137)
Total operating profit	$	21,981		$	35,705
Interest expense	5,~~566~~754			25,~~460~~566
Interest income	(43,~~428~~052)			(64,~~081~~428)
Closed mine obligations	~~2,381~~457			32,~~585~~381
Gain on equity securities	(1,805)			(1,958)
Loss (gain) on equity securities	726			(1,805)
Other, net	345			(3,985)
Gain on settlement of excess funding liability	(3,590)			—
Other expense (income), net	2,059			(5,979)
Pension settlement charge	7,804			—
Income (loss) before income tax benefit	33,646			(64,158)
Other, net	738			345
Income tax benefit	(95)			(24,571)
Other expense, net	8,837			2,059
Net income (loss)	$	33,741		$	(39,587)
Income before income tax benefit	13,144			33,646
Effective income tax rate	(0.3)		%	38.3		%
Income tax benefit	(4,430)			(95)
Net income	$	17,574		$	33,741
Effective income tax rate	(33.7)		%	(0.3)		%

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

Other expense ~~(income)~~, net

Interest expense increased modestly in ~~2024~~2025 compared with ~~2023~~2024 due to higher average borrowings, aspartially ~~well~~offset asby an increase in capitalized interest and lower average interest rates.

Interest income decreased in ~~2024~~2025 compared with ~~2023~~2024 due to lower earnings on reduced cash balances.

~~Gain~~Loss (gain) on equity securities represents changes in the market price of invested assets reported at fair value. The change during ~~2024~~2025 compared with ~~2023~~2024 was due to fluctuations in the market prices of the exchange-traded equity securities. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further discussion of our invested assets reported at fair value.

~~During~~Closed ~~2023,~~mine ~~our~~obligations ~~Board~~decreased ofin ~~Directors~~2025 ~~approved~~compared ~~the~~with ~~termination~~2024 ofdue ~~the~~to ~~Combined Defined Benefit Plan and participants were offered lump-sum distributions as part of the termination process. As~~ a ~~result~~change ofin the ~~lump-sum~~estimate ~~distributions, we recognized a non-cash, pension settlement charge~~ of ~~$1.8 million~~future inwater ~~2023~~treatment oncosts ~~the~~at ~~line Other, net within the accompanying Consolidated Statements of Operations~~Bellaire. See Note 147 to the Consolidated Financial Statements in this Form 10-K for further ~~information~~discussion onof ~~the~~our ~~Combined~~asset ~~Defined~~retirement ~~Benefit Plan~~obligations.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

OnDuring ~~December 1~~2025, ~~2022,~~ we ~~transferred~~terminated ~~our~~the ~~ownership~~NACCO ~~interest~~Combined inDefined ~~Midwest~~Benefit ~~AgEnergy~~Plan ~~Group, LLC~~ (~~MAG~~Combined Plan) and settled all future obligations by transferring the remaining benefit obligations to ~~HLCP~~a ~~Ethanol~~third-party ~~Holdco,~~insurance ~~LLC~~company. WeAlthough ~~received~~the ~~cash~~plan ~~payments~~was ~~totaling~~over funded, we recognized a $37.6 8 million ~~during~~non-cash ~~2023~~Pension insettlement ~~connection~~charge. ~~with~~See ~~MAG~~Note 1 and ~~recognized~~Note 14 to the ~~gain~~Consolidated onFinancial ~~the~~Statements ~~line~~in ~~Other,~~this ~~net~~Form ~~within~~10-K ~~the~~for ~~accompanying~~further ~~Consolidated~~information ~~Statements~~on ofthe ~~Operations~~Combined Plan.

During 2025, $14.5 million of excess funds from the terminated Falkirk Defined Benefit Plan were directly transferred to the NACCO 401(k) plan. The NACCO 401(k) plan is a qualified replacement plan; therefore, these funds will be utilized to offset future profit sharing contributions to eligible 401(k) plan participants. During 2025, NACCO and Falkirk’s former customer agreed to settle the corresponding liability for $10.9 million, resulting in a $3.6 million Gain on settlement of excess funding liability. See Note 1 to the Consolidated Financial Statements in this Form 10-K for further information on the excess funds.

Income Taxes

We recorded an income tax benefit of $04.14 million for the year ended December 31, ~~2024~~2025 on income before income tax of $3313.61 million, or 0(33.37)%, compared to an income tax benefit of $240.61 million on ~~loss~~income before income tax of $6433.26 million, or 38(0.3)%, for the year ended December 31, ~~2023~~2024. The years ended December 31, ~~2024~~2025 and ~~2023~~2024 ~~both~~ included $1.9 million and $4.0 million of discrete tax benefits, primarily ~~from~~for deferred tax adjustments and the reversal of uncertain tax provisions, respectively. Excluding the respective $1.9 million and $4.0 million of discrete tax benefits ~~in each year~~, the effective income tax rate inwas ~~2024~~(19.5)% and ~~2023 was~~ 11.5% in 2025 and ~~32.0%~~2024, respectively.

The change in the effective income tax rate for ~~2024~~2025 compared to ~~2023~~2024, excluding the impact of ~~the long-lived asset impairment charge and~~ discrete items, is primarily due to an increase in ~~earnings~~losses at entities that do not ~~qualify~~benefit ~~for~~from percentage depletion. ~~The~~Losses generated by these entities generate tax deductions at the statutory rate. This shift in the mix of pre-tax income resulted in a benefit tax rate in 2025. In addition, the benefit from percentage depletion is not directly related to the amount of pre-tax income recorded in a period. Accordingly, in periods where income or loss before income tax is relatively small, the proportional effect of the benefit from percentage depletion on the effective tax rate may be significant. When income tax expense is recorded, the benefit from percentage depletion decreases the effective income tax rate, while the effect is to increase the effective income tax rate when a benefit for income taxes is recorded.

See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of our income taxes.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following tables detail the change in cash flow for the years ended December 31:

	2024		2023		Change
	2025		2024		Change
Operating activities:
Net income (loss)	$	33,741	$	(39,587)	$	73,328
Net income	$	17,574	$	33,741	$	(16,167)
Depreciation, depletion and amortization	2425,~~652~~277		2924,~~387~~652		~~(4,735)~~625
Deferred income taxes	~~1,517~~58		~~(21~~1,~~114)~~517		22(1,~~631~~459)
Stock-based compensation	58,~~832~~280		5,~~157~~832		~~675~~2,448
(Gain) loss on sale of assets	(5,146)		221		(5,367)
Gain on sale of assets	(286)		(5,146)		4,860
Inventory impairment charges	96,~~643~~986		79,~~514~~643		(2,~~129~~657)
Long-lived asset impairment charge	—		65,887		(65,887)
Pension settlement charge	7,804		—		7,804
Other	(38,~~352)~~006		1(3,~~473~~352)		(411,~~825)~~358
Working capital changes	(44,598)		5,552		(50,150)
Changes in operating assets and liabilities	(22,790)		(44,598)		21,808
Net cash provided by operating activities	2250,~~289~~909		5422,~~490~~289		~~(32~~28,~~201)~~620
Investing activities:
Expenditures for property, plant and equipment and acquisition of mineral interests	(5553,~~419~~286)		(8255,~~122~~419)		262,~~703~~133
Proceeds from the sale of assets	~~822~~2,799		~~561~~822		~~261~~1,977
Proceeds from the sale of private company equity units	—		3,574		(3,574)
Equity method investment	(16,702)		(16,556)		(146)
Equity method investment	(16,556)		(3,464)		(13,092)
Return of equity method investment	3,295		—		3,295
Other	(~~139~~282)		(~~146~~139)		7(143)
Net cash used for investing activities	(7164,~~292~~176)		(8171,~~597~~292)		107,~~305~~116
Cash flow before financing activities	$	(4913,~~003~~267)	$	(2749,~~107~~003)	$	~~(21~~35,~~896)~~736

The $3228.26 million ~~unfavorable~~favorable change in net cash provided by operating activities during ~~2024~~2025 compared with ~~2023~~2024 was primarily due to anchanges ~~unfavorable~~in ~~change~~operating inassets ~~cash~~and ~~provided~~liabilities. byInventory ~~working~~levels ~~capital~~at December 31, ~~partially~~2025 ~~offset~~and byDecember an31,2024 ~~increase~~were inrelatively ~~cash~~consistent, ~~provided~~whereas byinventories ~~net~~increased ~~income~~during ~~adjusted~~2024. ~~for~~Accounts ~~non-cash~~receivable ~~items~~decreased during 2025 due to the timing of collections, whereas accounts receivable increased during 2024. ~~The~~These favorable items were partially offset by an unfavorable change in ~~working~~accrued ~~capital~~expenses, ~~was~~ mainly attributable to a decrease in accrued payroll during the ~~result~~2025 ~~of:~~period, whereas accrued payroll increased during 2024.

•A significant reduction in the Federal income tax receivable during 2023 that did not reoccur in 2024.


	2025		2024		Change
Financing activities:
Net additions to long-term debt and revolving credit agreements	$	11	$	55,710	$	(55,699)
Debt issuance costs	—		(2,415)		$	2,415
Cash dividends paid	(7,335)		(6,624)		(711)
Purchase of treasury shares	(2,534)		(9,944)		7,410
Net cash (used for) provided by financing activities	$	(9,858)	$	36,727	$	(46,585)

•The ~~changes~~change in ~~Inventory~~net ~~during~~cash ~~the~~(used ~~period~~for) asprovided ~~coal~~by ~~inventory~~financing ~~increased~~activities was primarily due to relatively consistent debt borrowings during ~~2024~~2025 compared with aadditions ~~decrease~~during ~~in 2023~~2024. InThis ~~addition,~~change ~~there~~ was apartially ~~larger~~offset ~~increase~~by decreases in ~~mining~~share ~~supplies~~repurchases ~~inventory~~and ~~during~~debt ~~2024.~~

•An increase in Trade accounts receivable during 2024 compared with a decrease during 2023, primarily due to changes in the level and timing of collections as well as the payment terms provided to various customers.50

Our non-cash items primarily include Long-lived asset impairment charge, Inventory impairment charges, Depreciation, depletion and amortization, Deferred income taxes, Stock-based compensation and (Gain) loss on sale of assets.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

	2024		2023		Change
Financing activities:
Net additions to long-term debt and revolving credit agreements	$	55,710	$	11,023	$	44,687
Debt issuance costs	(2,415)		—		$	(2,415)
Cash dividends paid	(6,624)		(6,452)		(172)
Purchase of treasury shares	(9,944)		(3,103)		(6,841)
Net cash provided by financing activities	$	36,727	$	1,468	$	35,259

issuance costs during 2025. See Note 12 to the Consolidated Financial Statements in this Form 10-K for a discussion of our stock repurchase programs.

The change in net cash provided by financing activities was primarily due to higher additions in debt borrowings during 2024 compared with 2023, partially offset by increased share repurchases and debt issuance costs during 2024. See Note 12 to the Consolidated Financial Statements in this Form 10-K for a discussion of our stock repurchase programs.

1031 exchange transactions

During 2024, we had cash proceeds from the sale of assets held by a qualified intermediary to facilitate tax-deferred exchange transactions under Section 1031 of the Internal Revenue Code. In May 2024, we sold land for $7.0 million and recognized a $4.5 million gain in the Minerals Management segment. We structured this transaction in a manner that qualified as a like-kind exchange pursuant to Section 1031 of the Internal Revenue Code and used all of the net proceeds from the sale during the year ended December 31, 2024.

Financing Activities

In September 2024, NACCO Natural Resources amended ~~the~~its secured revolving line of credit (Facility) to increase the revolving credit commitments to $200.0 million and extend the maturity to September 2028. Borrowings outstanding under the Facility were $7075.0 million at December 31, ~~2024~~2025. At December 31, ~~2024~~2025, the excess availability under the Facility was $9974.15 million, which reflects a reduction for outstanding letters of credit of $3050.95 million.

NACCO has not guaranteed any borrowings of NACCO Natural Resources. The Facility allows 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 us 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 December 31, ~~2024~~2025, for base rate and Term Secured Overnight Financing Rate loans were 1.50% and 2.50%, respectively. The Facility has a commitment fee which is based upon achieving various levels of net debt to EBITDA ratios. The commitment fee was 0.40% on the unused commitment at December 31, ~~2024~~2025. During the years ended December 31, ~~2024~~2025 and December 31, ~~2023~~2024, the average borrowing under the Facility was $2757.23 million and $627.2 million, respectively, and the weighted-average annual interest rate was 87.8321% and 68.0683%, respectively.

The Facility contains restrictive covenants, which require, among other things, NACCO Natural Resources to maintain a maximum net debt to EBITDA ratio of 2.75 to 1.00 and an interest coverage ratio of not less than 4.00 to 1.00. The Facility provides the ability to make loans, dividends and advances to NACCO, with some restrictions based on maintaining a maximum net debt to EBITDA ratio of 1.50 to 1.00, or if greater than 1.50 to 1.00, a Fixed Charge Coverage Ratio of 1.10 to 1.00. At December 31, ~~2024~~2025, NACCO Natural Resources was in compliance with all financial covenants in the Facility.

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

55We believe funds available from cash on hand, the Facility and operating cash flows will provide sufficient liquidity to meet our operating needs and commitments arising during the next twelve months and until the expiration of the Facility in September 2028.

See Note 8 and Note 10 to the Consolidated Financial Statements in this Form 10-K for further information on our other financing arrangements and leases, respectively.

Expenditures for property, plant and equipment and mineral interests

Following is a table which summarizes expenditures (in millions):


	Planned		Actual		Actual
	2026		2025		2024
NACCO	$	89.0	$	53.3	$	55.4

Actual expenditures for 2025 were $8.0 million in the Utility Coal Mining Segment, $32.0 million in the Contract Mining segment, $7.7 million in the Minerals and Royalties segment and $5.6 million in growth business included in Unallocated Items. Capital expenditures were primarily for a dragline and dragline related improvements in the Contract Mining segment.

Capital expenditures for 2026 are expected to be up to $6 million in the Utility Coal Mining segment, $36 million in the Contract Mining segment, $20 million in the Minerals and Royalties segment and $27 million in growth businesses included in

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

WeUnallocated ~~believe~~Items. ~~funds~~The ~~available~~majority ~~from~~of ~~cash~~these onexpenditures ~~hand,~~relate ~~the~~to ~~Facility~~business ~~and~~development ~~operating~~opportunities ~~cash~~and ~~flows~~ will ~~provide~~only ~~sufficient~~be ~~liquidity~~made toif the projects meet our ~~operating~~growth ~~needs~~investment ~~and~~criteria. ~~commitments~~Expenditures ~~arising~~are ~~during~~expected ~~the~~to ~~next~~be ~~twelve~~funded ~~months~~from ~~and~~internally ~~until~~generated ~~the~~funds ~~expiration~~and/or ofbank ~~the Facility in September 2028~~borrowings.

See Note 8 and Note 10 to the Consolidated Financial Statements in this Form 10-K for further information on our other financing arrangements and leases, respectively.

Expenditures for property, plant and equipment and mineral interests

Following is a table which summarizes actual and planned expenditures (in millions):

	Planned		Actual		Actual
	2025		2024		2023
NACCO	$	58.0	$	55.4	$	82.1

Planned expenditures for 2025 are expected to be approximately $13 million in the Coal Mining segment, $17 million in the NAMining segment, $20 million in the Minerals Management segment and $8 million in growth businesses included 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:

December 31

2024

2023

Change

2025

2024

Change

Cash and cash equivalents

7249,~~833~~708

8572,~~109~~833

(1223,~~276~~125)

Other net tangible assets

~~451~~500,~~962~~411

~~349~~451,~~934~~962

~~102~~48,~~028~~449

Intangible assets, net

54,~~475~~725

65,~~006~~475

(~~531~~750)

Net assets

~~530~~554,~~270~~844

~~441~~530,~~049~~270

8924,~~221~~574

Total debt

(99100,~~514~~895)

(3599,~~956~~514)

(631,~~558~~381)

Closed mine obligations

(2524,~~809~~706)

(2225,~~753~~809)

(31,~~056)~~103

Total equity

~~404~~429,~~947~~243

~~382~~404,~~340~~947

2224,~~607~~296

Debt to total capitalization

2019

920

11(1)

The increase in other net tangible assets was mainly the result of increases in Property, plant and equipment, ~~Other~~the ~~non-current~~Equity ~~assets~~method ~~and Inventory during 2024. The increase in Other non-current asset was primarily due to our~~ investment ~~of $15.7 million~~ in Eiger, ~~which~~Resources ~~holds non-operated working interests in oil~~ and ~~natural gas assets in~~ the ~~Kansas~~establishment ~~and the Oklahoma portion~~ of the ~~Hugoton~~Prepaid ~~basin.~~profit ~~The~~sharing ~~increase~~asset induring ~~Inventory was mainly due to higher mining supplies and coal inventory~~2025.

During 2025, we invested an additional $15.0 million in Eiger Resources, which holds operated and non-operated working interests in oil and natural gas assets in the Kansas and the Oklahoma portion of the Hugoton basin. This resulted in an increase in Equity method investment in Eiger Resources. See Note 1 to the Consolidated Financial Statements in this Form 10-K for further information on Eiger Resources.

The excess funds from the terminated Combined Plan as well as the excess funds from the Falkirk Defined Benefit Plan will be utilized by the NACCO 401(k) plan, which is a qualified replacement plan. These funds will be used for future profit sharing contributions to eligible 401(k) plan participants, which resulted in an increase in Prepaid profit sharing. See Note 1 to the Consolidated Financial Statements in this Form 10-K for further information on the excess funds.

Contractual Obligations, Contingent Liabilities and Commitments

Pension and postretirement funding can vary significantly each year due to plan amendments, changes in the market value of plan assets, legislation and our decisions to contribute above the minimum regulatory funding requirements. We do not expect to contribute to our pension plan in 2025 and any settlements will be paid out of pension plan assets. NACCO maintains one supplemental retirement plan that pays monthly benefits to participants directly out of corporate funds. NACCO also expects to make payments related to our other postretirement plans. See Note 14 to the Consolidated Financial Statements in this Form 10-K for further information on future benefit payments.

NACCO has asset retirement obligations. See Note 7 to the Consolidated Financial Statements in this Form 10-K for further discussion of our asset retirement obligations.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

NACCO has unrecognized tax benefits, including interest and penalties. See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of our income taxes.

We are a party to certain guarantees related to Coyote Creek. We believe that the likelihood of future performance under the guarantees is remote, and no amounts related to these guarantees have been recorded. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further discussion of our guarantees.

We utilize letters of credit to support commitments made in the ordinary course of business. As of December 31, ~~2024~~2025 and ~~2023~~2024, outstanding letters of credit totaled $3050.95 million and $3430.9 million, respectively.

ENVIRONMENTAL MATTERS

We are affected by the regulations of numerous agencies, particularly the Federal Office of Surface Mining, the U.S. Environmental Protection Agency, the U.S. Army Corps of Engineers and associated state regulatory authorities. In addition, we closely monitor proposed legislation and regulation concerning SMCRA, CAA, ACE, CWA, RCRA, CERCLA, OBBBA and other regulatory actions. See Item 1 and Item 1A. in Part I of this Form 10-K for further discussion of these matters.

Compliance with these increasingly stringent regulations could result in higher expenditures for both capital improvements and operating costs. The election of Donald Trump, paired with Republican control of Congress, is likely to have a significant and favorable impact on the regulatory environment, particularly for fossil fuels. President Trump issued an Executive Order on January 20, 2025, "Unleashing American Energy," directing all federal executive agency heads to review all agency actions implicating energy reliability and affordability or potentially burdening the development of domestic energy resources. It is not yet clear how existing regulations affecting existing fossil fuel assets will be reconsidered or repealed. Our policies stress environmental responsibility and compliance with these regulations. See Item 1 and Item 1A. in Part I of this Form 10-K for further discussion of these matters.52

SEGMENT RESULTS

COAL MINING SEGMENT

FINANCIAL REVIEW

See Item 2. Properties on page 29 in this Form 10-K for discussion of our mineral resources and mineral reserves.

Tons of coal delivered by the Coal Mining segment were as follows for the years ended December 31:

	2024	2023
Unconsolidated mines	21,308	20,741
Consolidated mines	1,922	2,931
Total tons delivered	23,230	23,672

The results of operations for the Coal Mining segment were as follows for the years ended December 31:

	2024		2023
Revenues	$	68,611	$	85,415
Cost of sales	79,375		108,760
Gross loss	(10,764)		(23,345)
Earnings of unconsolidated operations(a)	51,821		44,633
Business interruption insurance recoveries	13,612		—
Selling, general and administrative expenses and long-lived asset impairment charge	30,112		89,971
Amortization of intangible assets	531		2,998
Gain on sale of assets	(285)		(339)
Operating profit (loss)	$	24,311	$	(71,342)

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

SEGMENT RESULTS

UTILITY COAL MINING SEGMENT

FINANCIAL REVIEW

See Item 2. Properties on page 25 in this Form 10-K for discussion of our mineral resources and mineral reserves.

Tons of coal delivered by the Utility Coal Mining segment were as follows for the years ended December 31:


	2025	2024







Unconsolidated mines	20,400	21,308

Consolidated mines	2,730	1,922
Total tons delivered	23,130	23,230

The results of operations for the Utility Coal Mining segment were as follows for the years ended December 31:


	2025		2024
Revenues	$	88,188	$	68,611
Cost of sales	94,155		79,375
Gross loss	(5,967)		(10,764)
Earnings of unconsolidated operations(a)	54,471		51,821
Business interruption insurance recoveries	—		13,612
Selling, general and administrative expenses	30,702		30,112
Amortization of intangible assets	750		531
Gain on sale of assets	(103)		(285)
Operating profit	$	17,155	$	24,311

(a) See Note 16 to the Consolidated Financial Statements in this Form 10-K for a discussion of our unconsolidated subsidiaries, including summarized financial information.

~~2024~~2025 Compared with ~~2023~~2024

Revenues ~~decreased~~increased 1928.75% in ~~2024~~2025 compared with ~~2023~~2024 primarily due to aan ~~reduction~~increase in customer requirements at MLMC aspartially offset by a ~~result~~reduction ofin a the contractually determined per ton sales price. A boiler issue at the customer's Red Hills Power Plant reduced customer requirements in 2024.

The following table identifies the components of change in Operating profit ~~(loss)~~ for ~~2024~~2025 compared with ~~2023~~2024:

	Operating Profit (Loss)
	Operating Profit
2023	$	(71,342)
Increase (decrease) from:
Long-lived asset impairment charge in 2023	60,832
Business interruption insurance recoveries	13,612
Gross loss, excluding inventory impairment charges	14,710
Earnings of unconsolidated operations	7,188
Amortization of intangibles	2,467
Inventory impairment charges	(2,129)
Selling, general and administrative expenses	(973)
Net change on sale of assets	(54)
2024	$	24,311
Increase (decrease) from:
Business interruption insurance recoveries in 2024	(13,612)
Selling, general and administrative expenses	(590)
Amortization of intangibles	(219)
Net change on sale of assets	(182)
Gross loss	4,797
Earnings of unconsolidated operations	2,650
2025	$	17,155

~~Operating profit (loss) changed favorably by $95.7 million in 2024 compared with 2023. The change in Operating profit (loss) was primarily due to:~~53

•The absence of a long-lived asset impairment charge;

•Business interruption insurance recoveries for the boiler issue at the Red Hills Power Plant;

•A decrease in gross loss, excluding inventory impairment charges;

•An increase in the earnings of unconsolidated operations; and

•A decrease in the amortization of intangibles.

During 2023, MLMC received notice from its customer related to a boiler issue at the Red Hills Power Plant that began on December 15, 2023. We assessed for impairment and recorded a non-cash, long-lived asset impairment charge of $65.9 million in 2023. The $65.9 million relates exclusively to MLMC; however, $60.8 million and $5.1 million were recorded on the Coal Mining segment and the Minerals Management segment, respectively, as certain MLMC land assets were recorded within the Minerals Management segment. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on the 2023 impairment. While this issue has been resolved, it resulted in a reduction in customer demand which had a significant impact on our 2024 results of operations. We recognized income of $13.6 million in 2024 related to business interruption insurance recoveries that partially offset losses as a result of the boiler outage.

The reduction in revenues at MLMC was offset by lower cost of goods sold, resulting in a decrease in the gross loss during 2024 compared with 2023. The reduction in cost of goods sold was primarily attributable to changes in the level of coal inventory and costs capitalized into inventory as the decrease in demand resulted in an increase in the coal stockpile during 2024. In addition, the gross loss in 2024 and 2023 included $9.6 million and $7.5 million of inventory impairment charges, respectively, to write down MLMC's coal inventory to its net realizable value.

The increase in earnings of unconsolidated operations was primarily due to improved results at Falkirk, primarily due to a higher per ton management fee beginning in June 2024 when temporary price concessions ended and an increase in customer demand. Improved results at Coteau also contributed to the increase in earnings of unconsolidated operations.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

~~NORTH~~Operating ~~AMERICAN~~profit ~~MINING~~decreased ~~(NAMining)~~by ~~SEGMENT~~$7.2 million in 2025 compared with 2024 primarily due to the absence of MLMC's business interruption insurance recoveries for the boiler issue at the Red Hills Power Plant. This unfavorable change was partially offset by a decrease in gross loss and an increase in earnings of unconsolidated operations. Gross loss was favorable during 2025 compared with the 2024 period, primarily due to an increase in customer requirements and a reduction in cost per ton delivered. The increase in earnings of unconsolidated operations was primarily due to a higher per ton management fee at Falkirk as temporary price concessions ended in the second quarter of 2024.

CONTRACT MINING SEGMENT

FINANCIAL REVIEW

Aggregate tons delivered by the ~~NAMining~~Contract Mining segment were as follows for the years ended December 31:

	2024	2023
	2025	2024
Total tons delivered	54,~~963~~885	5654,~~655~~963

The results of operations for the ~~NAMining~~Contract Mining segment were as follows for the years ended December 31:

	2024		2023
	2025		2024
Total revenues	$	~~119~~140,~~600~~013	$	90119,~~532~~600
Reimbursable costs	7491,~~636~~116		5674,~~611~~636
Revenues excluding reimbursable costs	$	4448,~~964~~897	$	3344,~~921~~964
Revenues	$	~~119~~140,~~600~~013	$	90119,~~532~~600
Cost of sales	~~110~~129,~~821~~876		83110,~~719~~821
Gross profit	810,~~779~~137		68,~~813~~779
Earnings of unconsolidated operations(a)	54,~~010~~789		5,~~361~~010
Selling, general and administrative expenses	89,~~365~~321		8,~~308~~365
(Gain) loss on sale of assets	(348)		518
Gain on sale of assets	(162)		(348)
Operating profit	$	5,~~772~~767	$	35,~~348~~772

(a) See Note 16 to the Consolidated Financial Statements in this Form 10-K for a discussion of our unconsolidated subsidiaries, including summarized financial information.

~~2024~~2025 Compared with ~~2023~~2024

~~Revenues~~Total ~~excluding~~revenues ~~reimbursable costs~~ increased ~~32.6%~~ in ~~2024~~2025 compared with ~~2023~~2024, ~~mainly~~primarily due to ~~favorable pricing and delivery mix at the consolidated limestone quarries and~~ an increase in ~~the~~reimbursable ~~scope of work at Sawtooth. Reimbursable~~ costs, which have an offsetting amount in cost of sales and have no impact on gross profit,. ~~also~~Revenues excluding reimbursable costs increased ~~during~~8.7% in 2025 compared with 2024, mainly due to an increase in part sales.

The following table identifies the components of change in Operating profit for ~~2024~~2025 compared with ~~2023~~2024.

	Operating Profit
2023	$	3,348
Increase (decrease) from:
Gross profit	1,966
Net change on sale of assets	866
Earnings of unconsolidated operations	(351)
Selling, general and administrative expenses	(57)
2024	$	5,772
Increase (decrease) from:
Gross profit	1,358
Selling, general and administrative expenses	(956)
Net change on sale of assets	(186)
Earnings of unconsolidated operations	(221)
2025	$	5,767

Operating profit increased $2.4 million in 2024 compared with 2023 primarily due to an increase in gross profit and a favorable change on the sale of assets. The improvement in gross profit was mainly the result of favorable pricing and improved margins at the consolidated limestone quarries and an increase in the scope of work at Sawtooth. 54

Selling, general and administrative expenses include a $0.9 million charge to establish an allowance against a receivable from one of NAMining's customers during 2024, which was offset by a reduction in outside services.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

~~MINERALS~~Operating ~~MANAGEMENT~~profit ~~SEGMENT~~was comparable during 2025 and 2024. An increase in gross profit was largely offset by an increase in selling, general and administrative expenses. The improvement in gross profit was mainly the result of an increase in part sales partially offset by a $1.1 million charge to establish a loss contingency in 2025. The increase in selling, general and administrative expenses during 2025 was primarily the result of higher employee-related costs, partially offset by the absence of a $0.9 million prior year charge to establish an allowance against a customer receivable.

MINERALS AND ROYALTIES SEGMENT

FINANCIAL REVIEW

Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. The table below shows the average price as reported by the United States Energy Information Administration for the ~~twelve~~years ~~months~~ ended December 31:

	2024		2023
	2025		2024
West Texas Intermediate Average Crude Oil Price	$	7665.5546	$	7776.6455
Henry Hub Average Natural Gas Price	$	23.1953	$	2.5419

These indicated prices do not necessarily reflect the contract terms for our sales. As an owner of royalty and mineral interests, our access to information concerning activity and operations of our royalty and mineral interests is limited. We do not have information that would be available to a company with working interests in oil and natural gas operations because detailed information is not generally available to owners of royalty and mineral interests.

~~The~~As ~~results~~an owner of royalty and mineral interests, our access to information concerning activity and operations ~~for~~of ~~the~~our ~~Minerals~~royalty ~~Management~~and ~~segment~~mineral ~~were~~interests asis ~~follows~~limited. ~~for~~We ~~the~~do ~~years~~not ~~ended~~have ~~December 31:~~information that would be available to a company with working interests in oil and natural gas operations because detailed information is not generally available to owners of royalty and mineral interests.

	2024		2023
Oil and natural gas revenues	$	27,157	$	22,922
Other revenues	7,422		10,063
Total Revenues	$	34,579	$	32,985
Total Revenues	$	34,579	$	32,985
Cost of sales	5,234		3,969
Gross profit	29,345		29,016
Earnings of unconsolidated operations	647		—
Selling, general and administrative expenses and asset impairment charge	5,577		9,556
(Gain) loss on sale of assets	(4,512)		42
Operating profit	$	28,927	$	19,418

See Item 2. Properties on page 40 in this Form 10-K discussion of our proved reserves.

~~Revenues~~The ~~increased~~results inof ~~2024~~operations ~~compared~~for ~~with~~the ~~2023~~Minerals ~~primarily due to an increase in oil~~ and ~~natural~~Royalties ~~gas~~segment ~~revenues~~were as afollows ~~result~~for ~~of increased oil production volumes related to an acquisition that closed during~~ the ~~fourth~~years ~~quarter~~ended ~~of 2023. These improvements were partially offset by a reduction in other revenues, primarily coal royalty income. In addition, revenues during 2023 included $1.4 million of settlement income.~~December 31:

Operating profit increased $9.5 million in 2024 compared with 2023, primarily due to the absence of a $5.1 million long-lived asset impairment charge recognized during 2023 and a $4.5 million gain on the sale of land related to legacy operations recognized during 2024. The increase in revenue was offset by an increase in cost of sales, primarily related to higher depletion expense due to increased production volumes. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on the 2023 impairment.


	2025		2024
Oil and natural gas revenues	$	31,307	$	27,157
Other revenues	6,323		7,422
Total Revenues	$	37,630	$	34,579

Total Revenues	$	37,630	$	34,579
Cost of sales	5,666		5,234
Gross profit	31,964		29,345
Earnings of unconsolidated operations	2,571		647
Selling, general and administrative expenses	5,444		5,577
Gain on sale of assets	(17)		(4,512)
Operating profit	$	29,108	$	28,927

60Revenues increased 8.8% in 2025 compared with 2024 primarily due to an increase in natural gas revenue as a result of higher natural gas prices and increased production, partially offset by a decrease in oil revenue as a result of lower oil prices and decreased production.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

The following table identifies the components of change in Operating profit for 2025 compared with 2024.


	Operating Profit
2024	$	28,927
Increase (decrease) from:
Gross profit	2,619
Earnings of unconsolidated operations	1,924
Selling, general and administrative expenses	133
Gain on sale of assets	(4,495)
2025	$	29,108

Operating profit increased by $0.2 million in 2025 compared with 2024, primarily due to improvements in gross profit and earnings of unconsolidated operations. The increase in gross profit was mainly due to higher natural gas revenues. The increase in earnings of unconsolidated operations was primarily related to an additional investment in Eiger Resources during the fourth quarter of 2024. These increases were partially offset by the absence of a $4.5 million prior year gain on sale of land.

UNALLOCATED ITEMS AND ELIMINATIONS

FINANCIAL REVIEW

Unallocated Items and Eliminations were as follows for the years ended December 31:

	2024		2023
	2025		2024
Operating loss	$	(2330,~~305~~049)	$	(2123,~~561~~305)

~~2024~~2025 Compared with ~~2023~~2024

~~The~~Operating ~~operating~~ loss increased during ~~2024~~2025 compared with ~~2023~~2024 primarily due to an increase in selling, general and administrative expenses. This increase was mainly the result of higher employee-related costs, ~~partially~~and ~~offset~~increased bycosts ~~lower~~related ~~expenses~~to ~~for~~our ~~growth~~business ~~initiatives~~development asprojects. ~~certain~~Employee-related costs ~~expensed~~increased inprimarily ~~2023~~due ~~were~~to ~~capitalized~~elevated medical costs and higher share-based incentive compensation expense as a result of an increase in ~~2024~~our share price during 2025.

NACCO Industries, Inc. Outlook

NACCO's ~~businesses~~Industries ~~provide~~is ~~critical~~a ~~inputs~~growing ~~for~~diversified ~~electricity~~natural ~~generation,~~resources ~~construction~~company ~~and~~with ~~development,~~a ~~and~~unique ~~the~~business ~~production~~model ofstrategically ~~industrial~~positioned ~~minerals~~to deliver stable and ~~chemicals~~growing financial returns over the long term. ~~Increasing~~Our ~~demand~~business model is purposely built for ~~electricity,~~durability onand resilience with an expanding portfolio of long-~~shoring~~term contracts, relationships and ~~current~~investments ~~federal~~that ~~policies~~leverage ~~are~~our ~~creating~~proven ~~favorable~~operational ~~macroeconomic~~expertise, ~~trends~~disciplined ~~within~~capital ~~these~~allocation ~~industries~~and an entrepreneurial yet patient approach. We ~~are~~have ~~confident~~methodically inbuilt ~~our~~unique ~~trajectory~~capabilities and ~~business~~clear ~~prospects~~competitive asadvantages wethat ~~enter~~allow ~~2025~~us ~~and~~to ~~prepare~~pursue ~~for~~a ~~longer-term~~wide range of growth opportunities., ~~Specifically~~often completely integrated into customers’ operations in ~~2025~~partnership-based relationships. We have multiple vectors for value creation, and we ~~expect~~are steadfastly committed to ~~generate~~delivering acompounding ~~modest~~returns ~~year-over-year~~and ~~increase~~expanding ininvestor ~~consolidated~~value ~~operating~~over ~~profit~~the long term.

InOur ~~2025,~~foundation ~~the~~rests ~~Coal~~on ~~Mining~~a ~~segment~~stable ~~anticipates~~base ~~solid~~of ~~customer~~long-term ~~demand,~~coal-mining ~~with~~contracts ~~deliveries~~and ~~expected~~legacy tomineral ~~increase~~and ~~modestly~~royalty ~~from~~assets, ~~2024~~which generate dependable recurring cash flows. WeAs ~~anticipate~~new ~~that~~long-term ~~evolving~~contracts ~~policy~~and ~~frameworks~~investments ~~may~~are added across the Company, these new multi-year agreements create a ~~more~~“layering” ~~favorable~~effect ~~regulatory~~as ~~environment~~their ~~for~~contributions ~~the~~compound. ~~fossil~~This ~~fuel~~provides ~~industry~~cash ~~moving~~flow ~~forward~~stability. ~~These~~The ~~developments~~momentum ~~are~~our ~~expected~~operations toexperienced ~~further~~in ~~support~~2025, ~~coal~~particularly asin anthe ~~essential~~second ~~part~~half, ofis ~~the~~expected ~~energy~~to ~~mix~~continue into 2026, with meaningful year-over-year improvements in ~~the~~consolidated ~~United~~operating ~~States~~profit, ~~for~~net ~~the~~income ~~foreseeable~~and ~~future~~EBITDA.

~~The~~At our Utility Coal Mining segment, ~~expects~~operated toby ~~benefit~~North ~~from~~American ~~the expiration of temporary price concessions at Falkirk. In addition~~Coal, ~~MLMC~~we ~~continues~~expect toan ~~recover~~increase ~~from~~in ~~inefficiencies~~operating ~~experienced~~profit ~~while~~compared ~~its~~with ~~customer's Red Hills Power Plant operated on one of two generation units for more than half of 2024~~2025. ~~With~~Improvements ~~the~~at ~~power~~MLMC ~~plant~~as ~~now anticipated to operate at~~ a ~~level~~result ~~consistent~~of ~~with historical averages, coal deliveries are expected to return to more normal levels, resulting in moderate cost efficiencies. However,~~ an ~~anticipated~~increase ~~reduction~~ in the ~~2025~~ contractually determined per ton sales price ~~compared~~are ~~with 2024 is~~ expected to offset these improvements, resulting in lower results at MLMC. An expected increase in operating expenses will contribute to an overall anticipated modest year-over-year decrease in Coal Mining segment operating profit.

NAMining is expected to generate increasing levels of operating profit over time as the benefits of new and extended contracts add to the profitability of existing contracts. During 2024, NAMining executed three new or amended existing contracts, which are expected to deliver net present value after-tax cash flows of approximately $20 million over contract terms that range from 6 to 20 years. NAMining is expected to deliver further improved results in 2025, predominantly in the second half of the year based on expectations for comparable year-over-year customer demand. NAMining is continuously seeking to enter into new or amended contracts to solidify its position as the foundation for NACCO's mining-related growth initiatives.56

NAMining's subsidiary, Sawtooth, is the exclusive provider of comprehensive mining services at Thacker Pass, which is owned by Lithium Americas Corp. (TSX: LAC) (NYSE: LAC). Sawtooth will supply all of the lithium-bearing ore requirements for Thacker Pass, which is currently under construction. We expect to continue to recognize moderate income at Sawtooth while it assists with certain construction services. Once the mine is operating, Sawtooth will be reimbursed for costs of mining, capital expenditures and mine closure and will recognize a contractually agreed upon production fee. In addition to providing comprehensive mining services, Sawtooth will receive a fee to transport clay tailings once lithium production commences. Phase 1 lithium production is estimated to begin in late 2027.

The Minerals Management segment, through its Catapult business, has constructed a high-quality, diversified portfolio of oil and gas mineral and royalty interests in the United States. In the fourth quarter of 2024, Minerals Management invested $15.7 million in a company that holds non-operated working interests in oil and natural gas assets in the Kansas and Oklahoma portions of the Hugoton basin. While this investment, accounted for under the equity method, is expected to be accretive to earnings, 2025 operating profit is expected to be comparable to 2024. Lower first-half earnings are expected to be offset by an

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

~~improvement~~to inbe partly offset by lower earnings at the ~~second~~unconsolidated ~~half~~mining ~~given~~operations ~~expected~~due ~~trends~~to inreduced ~~oil~~income ~~and~~associated ~~natural~~with ~~gas~~the ~~prices~~wind ~~and~~down ~~projected~~of ~~volumes~~reclamation services at Sabine.

~~Minerals~~While ~~Management~~we ~~continues~~expect tomodest ~~build its portfolio with a mix of producing wells, near~~year-~~term development opportunities and undeveloped acreage. We believe our data~~over-~~driven~~year ~~approach~~improvements toat ~~acquisitions~~MLMC, ~~and~~the ~~our~~customer's ~~long-term~~power ~~perspective~~plant ~~provides~~began a ~~competitive~~maintenance ~~advantage~~outage asin ~~undeveloped~~mid-February ~~assets provide additional upside potential over the life of the reserve~~2026. ~~While~~The wepower ~~continue~~plant tois ~~budget~~expected up to ~~$20~~resume ~~million~~operations ~~annually~~in tomid-March. ~~expand~~Any ~~our~~delay ~~portfolio~~or ~~and~~further ~~provide~~changes ~~long-term~~in ~~stable cash flow generation~~demand, ~~our~~dispatch ~~business~~and/or ~~model~~reduced ~~allows~~mechanical ~~flexibility~~availability ~~regarding~~at the ~~cadence~~power ~~and~~plant ~~type~~could ofdecrease ~~investment~~current ~~based on available opportunities that we believe will create long-term value and generate increasing profitability~~expectations.

~~Mitigation~~The ~~Resources~~Contract ~~provides~~Mining ~~stream~~segment, ~~and~~operated ~~wetland~~by ~~mitigation~~North ~~solutions~~American asMining, ~~well~~serves as ~~comprehensive~~our ~~reclamation~~primary mining growth platform. Through continued geographic and ~~restoration~~mineral ~~construction~~expansion, ~~services.~~we ~~This~~are ~~business~~building isa angrowing ~~avenue~~portfolio ~~for~~of ~~growth~~long-term ~~and~~contracts ~~diversification~~that instrengthen anthe ~~area~~foundation ~~where~~for ~~NACCO~~sustained ~~has~~profitability. ~~built~~In October 2025, we secured a ~~strong~~multi-year ~~reputation~~dragline ~~based~~services oncontract ~~its~~as ~~substantial~~part ~~knowledge~~of ~~and~~a ~~expertise~~U.S. ~~Mitigation~~Army ~~Resources~~Corps ~~continued~~of toEngineers ~~expand~~construction ~~during~~project ~~2024~~in Palm Beach County, ~~and~~Florida. ~~now~~We ~~has~~also 11anticipate ~~mitigation~~commencing ~~banks~~operations ~~and~~at ~~other~~a ~~mitigation~~new ~~projects~~limestone ~~located~~quarry in ~~Alabama,~~Arizona ~~Florida,~~in ~~Georgia,~~2026. ~~Mississippi,~~We ~~Pennsylvania~~expect the segment to deliver a significant year-over-year increase in operating profit and Segment Adjusted EBITDA as a result of higher customer demand, ~~Tennessee~~earnings contributions from new contracts and ~~Texas.~~continued momentum from 2025 activities.

~~Mitigation~~Sawtooth, ~~Resources~~a ~~also~~North American Mining subsidiary, provides ~~ecological~~exclusive ~~restoration~~comprehensive mining services ~~for~~at ~~abandoned~~Thacker ~~surface~~Pass, ~~mines~~which ~~and~~is ~~plans~~owned toby ~~pursue~~a ~~other~~joint ~~environmental~~venture ~~restoration~~led ~~projects~~by Lithium Americas Corp. It(TSX: ~~was~~LAC; ~~named~~NYSE: aLAC). ~~designated~~Sawtooth ~~provider~~will supply all of ~~abandoned~~the ~~mine~~lithium-bearing ~~land~~ore ~~restoration~~requirements byfor ~~the~~our ~~State~~customer's ofThacker ~~Texas,~~Pass ~~and~~lithium inprocessing ~~January~~facility, ~~2025~~which ~~secured~~is acurrently ~~restoration~~under construction. This project inis ~~Kentucky~~providing ~~that~~stable income during construction and is expected to becontribute ~~accretive~~increased toincome ~~earnings~~and ~~beginning~~long-term incash ~~2026~~flows once lithium production commences, which is targeted for late 2027.

~~Mitigation~~The ~~Resources~~Minerals isand ~~expected~~Royalties tosegment, ~~achieve~~managed ~~full~~by Catapult, has constructed a high-~~year~~quality, ~~profitability~~diversified ~~beginning~~portfolio inof ~~2025~~oil ~~based~~and ongas ~~current~~mineral ~~expectations~~and ~~for~~royalty ~~the~~interests ~~timing~~in ofthe ~~permit~~United ~~approvals~~States. ~~and~~The ~~mitigation~~Catapult ~~credit~~team ~~releases,~~is asexpanding ~~well~~its asportfolio ~~income~~by ~~generated~~leveraging ~~from~~a ~~service~~data-~~related~~driven ~~projects.~~approach ~~Mitigation~~to ~~Resources~~capital isdeployment ~~expected~~that toincorporates ~~increase~~a ~~profitability~~longer-term ~~over~~view ~~time,~~of production and ~~provide~~development. aWe ~~return~~believe onthis ~~capital~~provides ~~employed~~a incompetitive ~~the~~advantage ~~mid-teens~~in as the ~~business~~U.S. ~~matures~~market.

WeIn ~~established~~July ~~ReGen~~2025, ~~Resources~~Catapult incompleted ~~2023~~a to$4.2 ~~address~~million acquisition of mineral interests within the ~~rapidly~~Permian ~~increasing~~Basin. ~~demand~~The ~~for~~acquisition includes a mix of producing wells, as well as additional ~~power~~development ~~generation~~opportunities ~~sources~~with existing operators in the ~~United~~area. ~~States~~This ~~through~~segment ~~development~~also ofhas ~~energy~~an ~~and~~investment ~~energy-related~~in ~~projects~~a company that ~~utilize~~holds ~~multiple~~operated and non-~~generation~~operated ~~technologies,~~working ~~such~~interests asin ~~solar~~oil ~~combined~~and ~~with~~natural gas~~-fired~~ ~~generation,~~assets. ~~primarily~~While onthese ~~reclaimed~~investments ~~mining~~are ~~properties.~~expected ~~These~~to ~~projects~~contribute ~~could~~favorably beto ~~developed~~2026, bycommodity ~~ReGen~~price ~~Resources~~forecasts ~~directly~~as orwell ~~through~~as ~~joint~~development ~~ventures~~and ~~that~~production ~~include~~assumptions ~~partners~~are ~~with~~expected ~~expertise~~to result in ~~energy~~an ~~development~~overall ~~projects.~~year-over-year ~~Current~~decrease ~~projects~~in ~~include~~Minerals ~~solar~~and ~~arrays~~Royalties' operating profit and Segment Adjusted EBITDA, ~~solar-gas~~particularly ~~hybrid~~in ~~projects~~the ~~and~~second ~~carbon~~half ~~capture~~of ~~projects~~the onyear. ~~reclaimed~~Our ~~mine~~forecast ~~land~~was developed prior to recent events in ~~Mississippi~~the ~~and~~Middle ~~Texas~~East. ~~Additional~~Any ~~projects~~changes in ~~other~~commodity ~~states~~prices ~~are~~or inproduction ~~early-stage~~as ~~review~~a result of this conflict could alter current expectations.

WeMitigation ~~are~~Resources ~~taking~~provides ~~actions~~natural toresource ~~terminate~~restoration ~~our~~and ~~defined~~reclamation ~~benefit~~services ~~pension~~that ~~plan~~include instream ~~2025,~~and ~~which~~wetland ~~will~~mitigation ~~eliminate~~solutions. ~~future~~Mitigation ~~volatility~~Resources ~~from~~is ~~changes~~successfully inleveraging ~~the~~its ~~pension~~strong ~~obligation.~~reputation ~~Once~~and ~~complete,~~clear ~~obligations~~competitive ~~under~~strengths ~~the~~to ~~terminated~~expand ~~plan~~into ~~will~~additional bemitigation, ~~transferred~~restoration toand areclamation ~~third-party insurance provider~~markets. ~~Surplus~~Mitigation ~~assets~~Resources ~~are~~is expected to bedeliver ~~utilized~~increasing toprofitability ~~fund~~over atime ~~qualified~~from ~~replacement~~the ~~plan,~~sale ~~reducing~~of ~~future~~mitigation ~~cash~~credits ~~funding~~and ~~requirements.~~as ~~Although~~reclamation ~~the~~and ~~plan~~restoration isservices ~~currently~~expand. ~~over~~This ~~funded~~business, awhile ~~significant~~currently ~~non-cash~~variable ~~settlement~~in ~~charge~~performance isdue ~~anticipated~~to ~~upon~~permit ~~termination,~~and ~~which~~project timing, is expected to ~~lead~~generate to a ~~substantial~~profit ~~year-over-year~~in ~~decrease~~the insecond ~~net~~half ~~income~~of 2026 and ~~EBITDA~~move ~~compared~~toward ~~with~~more ~~2024~~consistent results over time as the business expands.

~~Consolidated~~We ~~capital~~continue ~~expenditures~~to ~~are~~invest ~~expected~~in toour ~~total~~businesses ~~approximately~~to ~~$58~~drive ~~million~~future ingrowth. ~~2025~~In 2026, ~~which~~we ~~includes~~anticipate ~~approximately~~total ~~$13~~capital ~~million~~expenditures ~~for~~of ~~Coal~~up ~~Mining,~~to $1789 million. ~~for~~The ~~NAMining,~~majority ~~$20~~of ~~million~~these ~~for~~expenditures ~~Minerals~~relate ~~Management~~to business development opportunities and $8will ~~million~~only ~~predominantly~~be ~~for~~made ~~ReGen~~if ~~Resources~~the ~~and~~projects ~~other~~meet our growth ~~businesses~~investment criteria. WeThese ~~expect~~anticipated ~~significant~~capital ~~annual~~investments ~~cash~~are ~~flow~~expected ~~generation~~to ~~beginning~~result in ~~2025,~~a ~~based~~use onof ~~the~~cash ~~current~~before ~~business~~financing ~~plan~~greater than in 2025.

WeOur ~~believe~~businesses ~~that~~provide ~~each~~critical ofinputs ~~our~~for ~~businesses~~electricity ~~have~~generation, ~~competitive~~construction ~~advantages~~and ~~that~~development, ~~provide~~and ~~value~~the toproduction ~~customers~~of ~~and~~industrial ~~create~~minerals ~~long-term~~and ~~value for stockholders~~chemicals. WeAs ~~are~~the ~~pursuing~~need ~~growth~~for ~~and~~uninterrupted ~~diversification~~energy bygrows, ~~strategically~~industry ~~leveraging~~fundamentals ~~our~~for ~~core~~ natural resources ~~management~~are ~~skills~~expected to ~~build~~continue ato ~~robust~~strengthen, ~~portfolio~~reinforcing ofthe ~~affiliated~~critical ~~businesses.~~need ~~Opportunities~~to ~~for~~keep ~~growth~~existing, ~~remain~~reliable ~~strong~~baseload ~~and~~resources ~~are~~online. ~~increasing~~In ~~amid~~2026, ~~recent~~the ~~successes~~National ~~and~~Coal aCouncil, ~~significant~~an ~~positive~~advisory ~~change~~committee into the ~~regulatory~~U.S. ~~environment,~~Secretary ~~particularly~~of ~~for~~Energy, ~~fossil~~was ~~fuels~~re-established. ~~Acquisitions~~This council is focused on advising the Department of ~~additional~~Energy ~~mineral~~on ~~interests~~reinforcing ~~and~~coal’s ~~improvements~~strategic role in ~~the~~U.S. ~~outlook~~energy ~~for~~policy ~~Coal~~and ~~Mining~~providing ~~segment~~actionable ~~customers,~~advice ason ~~well~~sustaining ascoal ~~new~~plant ~~contracts~~operations atand ~~Mitigation~~prioritizing ~~Resources~~coal to support grid reliability to support our country’s economic competitiveness and ~~NAMining~~national ~~should~~security. beThe ~~accretive~~re-establishment toof this council and the ~~longer-term~~underlying ~~outlook.~~ improving regulatory

We are committed to maintaining a conservative capital structure as we continue to grow and diversify, while avoiding unnecessary risk. We believe strategic diversification will generate cash that can be re-invested to strengthen and expand the businesses or distributed to investors in the form of share repurchases or dividends. We continue to maintain the highest levels 57

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

ofenvironment ~~customer~~reinforce ~~service~~our ~~and~~confidence ~~operational~~in ~~excellence~~our ~~with~~prospects anfor ~~unwavering~~2026, ~~focus~~our onoverall ~~safety~~business trajectory and ~~environmental~~longer-term ~~stewardship~~growth opportunities.

Our conservative approach to maintaining a strong capital structure and operating discipline minimizes risk, while the compounding effect of a growing portfolio of long-term contracts and deliberate growth investments create a robust foundation for cash flow growth. With a perspective that spans decades, we are methodically building a strong, stable business that is expected to deliver annuity-like returns. This long-term view allows us to leverage our core skills for strategic, measured expansion and pursue opportunities with longer-term horizons and higher returns. We pursue opportunities that other companies with shorter time horizons might overlook. Our commitment is to generate increasing cash flows and return value to stockholders, whether through reinvestment for growth or direct returns such as share repurchases and payment of dividends. We remain confident in our ability to drive growth, expand our capabilities and reward shareholders over the long run.

RECENTLY ISSUED ACCOUNTING STANDARDS

See Note 2 to the Consolidated Financial Statements in this Form 10-K for a description of recently issued accounting standards including actual and expected dates of adoption and effects to our Consolidated Financial Statements.

FORWARD-LOOKING STATEMENTS

The statements contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere throughout this Annual Report on Form 10-K 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. We undertake 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~~significant orreduction ~~other~~in ~~third~~demand ~~party~~by ~~default~~the ~~under~~Company's ~~a contract~~customers, (2) ~~any~~weather ~~customer's~~conditions, ~~premature~~extended ~~facility~~power ~~closure~~plant oroutages, ~~extended~~liquidity ~~project~~events ~~development~~or ~~delay,~~other ~~(3)~~events ~~regulatory~~that ~~actions,~~would ~~including~~change the ~~United~~level ~~States~~of ~~EPA~~customers's ~~rules finalized in 2024 relating to mercury and greenhouse gas emissions for~~ coal~~-fired~~ ~~power plants, changes in mining permit requirements~~ or ~~delays~~aggregates ~~in obtaining mining permits that could affect deliveries to customers~~requirements, (43) ~~a significant reduction in purchases by the Company's customers, including as a result of~~ changes into ~~coal~~or ~~consumption~~termination ~~patterns~~ of ~~U.S.~~customer ~~electric~~or ~~power~~other ~~generators~~third-party contracts, or ~~changes~~a incustomer ~~the~~or ~~power~~other ~~industry~~third ~~that~~party ~~would~~default ~~affect~~under ~~demand~~a ~~for the Company's coal and other mineral reserves~~contract, (54) changes in the prices of hydrocarbons, particularly diesel fuel, natural gas, natural gas liquids and oil as a result of factors such as OPEC and/or government actions, geopolitical developments, economic conditions and regulatory changes, vehicle electrification, as well as supply and demand dynamics, (65) changes in development plans by third-party lessees of the Company's mineral interests, (76) 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 U.S. export of natural gas; 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) any customer's premature facility closure or extended project development delay, (8) ~~failure~~federal toand ~~obtain~~state ~~adequate~~legislative ~~insurance~~and ~~coverages~~regulatory atactions ~~reasonable~~affecting ~~rates~~fossil fuels, (9) supply chain disruptions, including price increases and shortages of parts and materials, inclusive of tariff effects, (10) failure to obtain adequate insurance coverages at reasonable rates, (11) 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, (1112) impairment charges, (1213) changes in costs related to geological and geotechnical conditions, repairs and maintenance, new equipment and replacement parts, fuel or other similar items, (~~13) weather conditions, extended power plant outages, liquidity events or other events that would change the level of customers' coal or aggregates requirements, (~~14) ~~weather or~~ equipment problems that could affect deliveries to customers, (15) changes in the costs to reclaim mining areas, (16) costs to pursue and develop new mining, mitigation, oil and gas and ~~solar~~power generation development opportunities and other value-added service opportunities, (17) ~~delays or reductions in coal or aggregates deliveries, (18)~~ the ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives, (1918) 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 (2019) the ability to attract, retain, and replace workforce and administrative employees.

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Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this Item 8 is set forth in the Financial Statements and Supplementary Data contained in Part IV of this Form 10-K and is hereby incorporated herein by reference to such information.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

There were no disagreements with accountants on accounting and financial disclosure for the two-year period ended December 31, ~~2024~~2025 that require disclosure pursuant to this Item 9.

Item 9A. CONTROLS AND PROCEDURES

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

Management's report on internal control over financial reporting: Management is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on this evaluation under the framework, management concluded that our internal control over financial reporting was effective as of December 31, ~~2024~~2025. Our effectiveness of internal control over financial reporting as of December 31, ~~2024~~2025 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included in Item 15 of this Form 10-K and incorporated herein by reference.

Changes in internal control: There have been no changes in our internal control over financial reporting, that occurred during the fourth quarter of ~~2024~~2025, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. OTHER INFORMATION

During the fourth quarter of ~~2024~~2025, none of our directors or executive officers adopted or terminated a Rule 10b5-1 Trading Plan, or a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).

Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.

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PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information with respect to our Directors will be set forth in the ~~2025~~2026 Proxy Statement under the subheadings Part III — Proposals To Be Voted On At The ~~2025~~2026 Annual Meeting — Proposal 1 — Election of Directors which information is incorporated herein by reference.

Information with respect to the audit review committee and the audit review committee financial expert will be set forth in the ~~2025~~2026 Proxy Statement under the subheading Part I — Corporate Governance Information — Directors' Meetings and Committees, which information is incorporated herein by reference.

Information with respect to compliance with Section 16(a) of the Securities Exchange Act of 1934 by our Directors, executive officers and holders of more than ten percent of our equity securities will be set forth in the ~~2025~~2026 Proxy Statement under the subheading Part IV — Other Important Information, which information is incorporated herein by reference.

We have adopted a code of business conduct and ethics applicable to all Company personnel, including the principal executive officer, principal financial officer, principal accounting officer or controller, or other persons performing similar functions. The code of business conduct and ethics, entitled the Code of Corporate Conduct, is posted on our website at www.nacco.com under Corporate Governance. If we make any amendments to or grant any waivers from the code of business conduct and ethics which are required to be disclosed pursuant to the Securities and Exchange Act of 1934, we will make such disclosure on the NACCO website.

We have adopted an insider trading policy that governs the purchase, sale and other disposition of our securities by our directors, officers and employees that is designated to promote compliance with insider trading laws, rules, regulations and applicable listing standards. A copy of our insider trading policy iswas filed as Exhibit 19 to ~~this~~the Annual Report on Form 10-K for the year ended December 31, 2024.

Item 11. EXECUTIVE COMPENSATION

Information with respect to executive compensation will be set forth in the ~~2025~~2026 Proxy Statement under the headings Part II — Executive Compensation Information and Part III — Proposals To Be Voted On At The ~~2025~~2026 Annual Meeting — Proposal 1 — Election of Directors, which information is incorporated herein by reference.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information with respect to security ownership of certain beneficial owners and management will be set forth in the ~~2025~~2026 Proxy Statement under the subheading Part IV — Other Important Information — Beneficial Ownership of Class A Common and Class B Common, which information is incorporated herein by reference.

Information with respect to compensation plans (including individual compensation arrangements) under which equity securities are authorized for issuance will be set forth in the ~~2025~~2026 Proxy Statement under the subheading Part IV — Other Important Information — Equity Compensation Plan Information, which information is incorporated herein by reference.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information with respect to certain relationships and related transactions will be set forth in the ~~2025~~2026 Proxy Statement under the subheadings Part I — Corporate Governance Information — Review and Approval of Related-Person Transactions, which information is incorporated herein by reference.

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information with respect to principal accountant fees and services will be set forth in the ~~2025~~2026 Proxy Statement under the heading Part III — Proposals To Be Voted On At The ~~2025~~2026 Annual Meeting — Proposal 45 — Ratification of the Appointment of Company's Independent Registered Public Accounting Firm, which information is incorporated herein by reference.

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PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) (1) and (2) The response to Item 15(a)(1) and (2) is set forth beginning at page F-1 of this Form 10-K.

(b) Financial Statement Schedules — The response to Item 15(c) is set forth beginning at page F-4240 of this Form 10-K.


Exhibit Number						Exhibit Description
(3) Articles of Incorporation and By-laws.
3.1(i)						Restated Certificate of Incorporation of the Company is incorporated herein by reference to Exhibit 3(i) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File Number 1-9172.
3.1(ii)						Certificate of Amendment of the Restated Certificate of Incorporation of the Company, dated July 23, 2024, is incorporated herein by reference to Exhibit 3(ii) to the Company's Quarterly Report on Form 10-Q, filed by the Company on July 31, 2024, Commission File Number 1-9172.
3.1(iii)						Amended and Restated By-laws of the Company are incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, filed by the Company on December 18, 2014, Commission File Number 1-9172.



(4) Instruments defining the rights of security holders, including indentures.
4.1						The Company by this filing agrees, upon request, to file with the Securities and Exchange Commission the instruments defining the rights of holders of long-term debt of the Company and its subsidiaries where the total amount of securities authorized thereunder does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis.
4.2						Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, among NACCO Industries, Inc., the other signatories thereto and NACCO Industries, Inc., as depository, is incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K, filed by the Company on October 5, 2017, Commission File Number 1-9172.
4.3						Amendment to Amended and Restated Stockholders' Agreement, dated as of February 14, 2019, among NACCO Industries, Inc., the other signatories thereto and NACCO Industries, Inc., as depository, is incorporated by reference to Exhibit 4.5 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, Commission File Number 1-9172.
4.4						Second Amendment to Amended and Restated Stockholders' Agreement, dated as of February 12, 2021, by and among the Depository, NACCO Industries, Inc., the new Participating Stockholders identified on the signature pages thereto and the Participating Stockholders under the Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, as amended, is incorporated by reference to Exhibit 99.60 of the Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on February 12, 2021, Commission File Number 1-9172.
4.5						Third Amendment to Amended and Restated Stockholders' Agreement, dated as of February 11, 2022, by and among the Depository, NACCO Industries, Inc., the new Participating Stockholders identified on the signature pages thereto and the Participating Stockholders under the Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, as amended, is incorporated by reference to Exhibit 99.62 of the Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on February 11, 2022, Commission File Number 1-9172.
4.6						Fourth Amendment to Amended and Restated Stockholders' Agreement, dated as of February 10, 2023, by and among the Depository, NACCO Industries, Inc., the new Participating Stockholders identified on the signature pages thereto and the Participating Stockholders under the Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, as amended, is incorporated by reference to Exhibit 99.67 of the Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on February 10, 2023, Commission File Number 1-9172.
4.7						Fifth Amendment to Amended and Restated Stockholders' Agreement, dated as of February 9, 2024, by and among the Depository, NACCO Industries, Inc., the new Participating Stockholders identified on the signature pages thereto and the Participating Stockholders under the Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, as amended, is incorporated by reference to Exhibit 99.69 of the Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on February 12, 2024, Commission File Number 1-9172.

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Exhibit Number						Exhibit Description
4.8						Sixth Amendment to Amended and Restated Stockholders’ Agreement, dated as of December 16, 2024, by and among the Depository, NACCO Industries, Inc., the new Participating Stockholders identified on the signature pages thereto and the Participating Stockholders under the Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, as amended, is incorporated by reference to Exhibit 99.71 of the Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on December 17, 2024, Commission File Number 1-9172.
4.9						Description of Securities is incorporated herein by reference to Exhibit 4.6 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, Commission File Number 1-9172.
(10) Material contracts
10.1*						NACCO Industries, Inc. Supplemental Executive Long-Term Incentive Bonus Plan (Amended and Restated March 1, 2012) is incorporated herein by reference to Appendix B to NACCO's Definitive Proxy Statement, filed by NACCO on March 16, 2012, Commission File Number 1-9172.
10.2*						NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan (Amended and Restated March 1, 2023) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on May 16, 2023, Commission File Number 1-9172.
10.3*						Amendment No. 1 to NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan (Amended and Restated March 1, 2023), dated as of February 20, 2024, is incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed by the Company on February 22, 2024, Commission File Number 1-9172.
10.4*						NACCO Industries, Inc. Non-Employee Directors' Equity Compensation Plan (Amended and Restated May 19, 2021) is incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed by the Company on May 19, 2021, Commission File Number 1-9172.
10.5*						Amendment No. 1 to NACCO Industries, Inc. Non-Employee Directors' Equity Compensation Plan (Amended and Restated May 19, 2021), dated as of February 20, 2024, is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on February 22, 2024, Commission File Number 1-9172.
10.6*						~~Form of Award Agreement for the~~ NACCO Industries, Inc. ~~Supplemental Executive Long~~Non-~~Term~~Employee ~~Incentive~~Directors' ~~Bonus~~Equity Compensation Plan (Amended and Restated May 14, 2025) is incorporated herein by reference to Exhibit 10.81 to the Company's Current Report on Form 8-K, filed by the Company on ~~September~~May 1719, ~~2012~~2025, Commission File Number 1-9172.
10.7*						Form of ~~Cashless Exercise~~ Award Agreement for the NACCO Industries, Inc. Supplemental Executive Long-Term Incentive ~~Compensation~~Bonus Plan is incorporated ~~herein~~ by reference to Exhibit 10.18 to the Company's ~~Quarterly~~Current Report on Form 108-QK, filed by the Company on ~~May~~September 117, ~~2024~~2012, Commission File Number 1-9172.
10.8*						Form of ~~Non-~~Cashless Exercise Award Agreement for the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan is incorporated herein by reference to Exhibit 10.101 to the Company's ~~Annual~~Quarterly Report on Form 10-KQ, ~~for~~filed by the ~~fiscal~~Company ~~year~~on ~~ended~~May ~~December 31~~1, ~~2019~~2024, Commission File Number 1-9172.
10.9						Consulting Agreement, dated as of September 29, 2017, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.5 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on October 5, 2017, Commission File Number 1-9172.
10.9*						Form of Non-Cashless Exercise Award Agreement for the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan is incorporated herein by reference to Exhibit 10.10 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, Commission File Number 1-9172.
10.10						~~Amendment to~~ Consulting Agreement, dated as of ~~December~~September 1529, ~~2020~~2017, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.15 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on ~~December~~October 155, ~~2020~~2017, Commission File Number 1-9172.
10.11						Amendment to Consulting Agreement, dated as of December 2115, ~~2021~~2020, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.1 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on December 2215, ~~2021~~2020, Commission File Number 1-9172.
10.12						Amendment to Consulting Agreement, dated as of December 1921, ~~2023~~2021, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.1 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on December 1922, ~~2023~~2021, Commission File Number 1-9172.
10.13						Amendment to Consulting Agreement, dated as of December 19, ~~2024~~2023, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.1 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on December 2319, ~~2024~~2023, Commission File Number 1-9172.
10.14*						NACCO Industries, Inc. Short-Term Incentive Compensation Plan (Effective as of March 1, 2019) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on February 13, 2019, Commission File Number 1-9172.
10.14						Amendment to Consulting Agreement, dated as of December 19, 2024, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.1 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on December 23, 2024, Commission File Number 1-9172.
10.15*						The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.12 to the Company’s Current Report on Form 8-K, filed by the Company on December 19, 2007, Commission File Number 1-9172.

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Exhibit Number						Exhibit Description
10.16*						Amendment No. 1 to The North America Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.41 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2009, Commission File Number 1-9172.
10.15*						NACCO Industries, Inc. Short-Term Incentive Compensation Plan (Effective as of March 1, 2019) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on February 13, 2019, Commission File Number 1-9172.
10.17*						The North American Coal Corporation Annual Incentive Compensation Plan (Amended and Restated Effective March 1, 2015) is incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, filed by the Company on May 18, 2015, Commission File Number 1-9172.
10.16*						The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.12 to the Company’s Current Report on Form 8-K, filed by the Company on December 19, 2007, Commission File Number 1-9172.
10.18*						Amendment No. 2 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.40 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2010, Commission File Number 1-9172.
10.17*						Amendment No. 1 to The North America Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.41 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2009, Commission File Number 1-9172.
10.19						Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of January 1, 1990, is incorporated herein by reference to Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.18*						The North American Coal Corporation Annual Incentive Compensation Plan (Amended and Restated Effective March 1, 2015) is incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, filed by the Company on May 18, 2015, Commission File Number 1-9172.
10.20						First Amendment to Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of June 1, 1994, is incorporated herein by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.19*						Amendment No. 2 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.40 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2010, Commission File Number 1-9172.
10.21						Second Amendment to Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of January 1, 1997, is incorporated herein by reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.20						Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of January 1, 1990, is incorporated herein by reference to Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.22						Option and Put Agreement by and among The North American Coal Corporation, Dakota Coal Company and the State of North Dakota, dated as of January 1, 1990, is incorporated herein by reference to Exhibit 10.14 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.21						First Amendment to Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of June 1, 1994, is incorporated herein by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.23						First Amendment to the Option and Put Agreement by and among The North American Coal Corporation, Dakota Coal Company and the State of North Dakota, dated as of June 1, 1994, is incorporated herein by reference to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.22						Second Amendment to Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of January 1, 1997, is incorporated herein by reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.24						Lignite Sales Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of April 1, 1998, is incorporated herein by reference to Exhibit 10.16 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.23						Option and Put Agreement by and among The North American Coal Corporation, Dakota Coal Company and the State of North Dakota, dated as of January 1, 1990, is incorporated herein by reference to Exhibit 10.14 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.25						First Amendment to Lignite Sales Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of August 30, 2016, is incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q, filed by the Company on November 1, 2016, Commission File Number 1-9172.
10.24						First Amendment to the Option and Put Agreement by and among The North American Coal Corporation, Dakota Coal Company and the State of North Dakota, dated as of June 1, 1994, is incorporated herein by reference to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.26						Pay Scale Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of September 29, 2005, is incorporated herein by reference to Exhibit 10.17 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.25						Lignite Sales Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of April 1, 1998, is incorporated herein by reference to Exhibit 10.16 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.27						Consent and Agreement by and among Mississippi Lignite Mining Company, Choctaw Generation Limited Partnership, SE Choctaw L.L.C. and Citibank, N.A., dated as of December 20, 2002, is incorporated herein by reference to Exhibit 10.29 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.26						First Amendment to Lignite Sales Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of August 30, 2016, is incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q, filed by the Company on November 1, 2016, Commission File Number 1-9172.
10.28						Amendment No. 1 to Lignite Sales Agreement, Settlement Agreement and Release by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, LLLP, dated as of November 16, 2018, is incorporated herein by reference to Exhibit 10.33 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, Commission File Number 1-9172.
10.27						Pay Scale Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of September 29, 2005, is incorporated herein by reference to Exhibit 10.17 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.29						Amendment No. 2 to Lignite Sales Agreement, Settlement Agreement and Release by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, LLLP, dated as of November 24, 2021, is incorporated herein by reference to Exhibit 10.29 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2021, Commission File Number 1-9172.
10.28						Consent and Agreement by and among Mississippi Lignite Mining Company, Choctaw Generation Limited Partnership, SE Choctaw L.L.C. and Citibank, N.A., dated as of December 20, 2002, is incorporated herein by reference to Exhibit 10.29 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.30						Termination Agreement and Release, by and among The Falkirk Mining Company, Great River Energy and NoDak Energy Investments Corporation, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.29						Amendment No. 1 to Lignite Sales Agreement, Settlement Agreement and Release by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, LLLP, dated as of November 16, 2018, is incorporated herein by reference to Exhibit 10.33 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, Commission File Number 1-9172.
10.31						Amendment No. 1 to Termination Agreement and Release, by and between The Falkirk Mining Company, NoDak Energy Investments Corporation and Great River Energy, dated as of December 28, 2021, is incorporated herein by reference to Exhibit 10.36 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2021, Commission File Number 1-9172.
10.30						Amendment No. 2 to Lignite Sales Agreement, Settlement Agreement and Release by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, LLLP, dated as of November 24, 2021, is incorporated herein by reference to Exhibit 10.29 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2021, Commission File Number 1-9172.

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Exhibit Number						Exhibit Description
10.32***						Coal Sales Agreement, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.31						Termination Agreement and Release, by and among The Falkirk Mining Company, Great River Energy and NoDak Energy Investments Corporation, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.33						First Amendment to Coal Sales Agreement, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated March 8, 2022, is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on May 4, 2022, Commission File Number 1-9172.
10.32						Amendment No. 1 to Termination Agreement and Release, by and between The Falkirk Mining Company, NoDak Energy Investments Corporation and Great River Energy, dated as of December 28, 2021, is incorporated herein by reference to Exhibit 10.36 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2021, Commission File Number 1-9172.
10.34						Second Amendment to Coal Sales Agreement, by and between the Falkirk Mining Company and Rainbow Energy Center, LLC, dated August 5, 2022, is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on November 2, 2022, Commission File Number 1-9172.
10.33***						Coal Sales Agreement, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.35***						Guaranty by REMC Assets, LP, dated June 17, 2021, is incorporated herein by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.34						First Amendment to Coal Sales Agreement, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated March 8, 2022, is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on May 4, 2022, Commission File Number 1-9172.
10.36***						Mortgage, Assignment of Leases, Rents and As-Extracted Collateral, Security Agreement, Financing Statement and Fixture Filing, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.35						Second Amendment to Coal Sales Agreement, by and between the Falkirk Mining Company and Rainbow Energy Center, LLC, dated August 5, 2022, is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on November 2, 2022, Commission File Number 1-9172.
10.37						Security Agreement, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.36***						Guaranty by REMC Assets, LP, dated June 17, 2021, is incorporated herein by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.38						Option Agreement, by and between The Falkirk Mining Company, Rainbow Energy Center, LLC and the State of North Dakota, Doing Business as The Bank of North Dakota, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.37***						Mortgage, Assignment of Leases, Rents and As-Extracted Collateral, Security Agreement, Financing Statement and Fixture Filing, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.39						Lignite Sales Agreement between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co. and Northwestern Corporation dated as of October 10, 2012 is incorporated herein by reference to Exhibit 10.58 to the Company’s Annual Report on Form 10-K, filed by the Company on March 6, 2013, Commission File Number 1-9172.++
10.38						Security Agreement, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.40						First Amendment to Lignite Sales Agreement, dated as of January 30, 2014, between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. and NorthWestern Corporation is incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 8-K, filed by the Company on January 30, 2014, Commission File Number 1-9172.
10.39						Option Agreement, by and between The Falkirk Mining Company, Rainbow Energy Center, LLC and the State of North Dakota, Doing Business as The Bank of North Dakota, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.41						Second Amendment to Lignite Sales Agreement, dated as of March 16, 2015, between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., and NorthWestern Corporation is incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q, filed by the Company on May 5, 2015, Commission File Number 1-9172.
10.40						Lignite Sales Agreement between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co. and Northwestern Corporation dated as of October 10, 2012 is incorporated herein by reference to Exhibit 10.58 to the Company’s Annual Report on Form 10-K, filed by the Company on March 6, 2013, Commission File Number 1-9172.++
10.42*						Amendment No. 3 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on October 30, 2013, Commission File Number 1-9172.
10.41						First Amendment to Lignite Sales Agreement, dated as of January 30, 2014, between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. and NorthWestern Corporation is incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 8-K, filed by the Company on January 30, 2014, Commission File Number 1-9172.
10.43*						Amendment No. 4 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.54 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2014, Commission File Number 1-9172.
10.42						Second Amendment to Lignite Sales Agreement, dated as of March 16, 2015, between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., and NorthWestern Corporation is incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q, filed by the Company on May 5, 2015, Commission File Number 1-9172.
10.44*						Amendment No. 5 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.57 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, Commission File Number I-9172.
10.43*						Amendment No. 3 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on October 30, 2013, Commission File Number 1-9172.
10.45*						Amendment No. 6 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.52 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, Commission File Number I-9172.
10.44*						Amendment No. 4 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.54 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2014, Commission File Number 1-9172.
10.46						Agreement, dated as of March 16, 2015, among The North American Coal Corporation, Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. and Northwestern Corporation is incorporated herein by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed by the Company on May 5, 2015, Commission File Number 1-9172.
10.45*						Amendment No. 5 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.57 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, Commission File Number I-9172.
10.47*						The North American Coal Corporation Excess Retirement Plan (Amended and Restated Effective January 1, 2020) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on December 18, 2019, Commission File Number 1-9172.
10.46*						Amendment No. 6 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.52 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, Commission File Number I-9172.

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Exhibit Number						Exhibit Description
10.48*						The NACCO Natural Resources Excess Retirement Plan (Effective January 1, 2025) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on December 17, 2024, Commission File Number 1-9172.
10.47						Agreement, dated as of March 16, 2015, among The North American Coal Corporation, Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. and Northwestern Corporation is incorporated herein by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed by the Company on May 5, 2015, Commission File Number 1-9172.
10.49						Amended and Restated Credit Agreement by and among The North American Coal Corporation and the Guarantors party thereto and the Lenders party thereto and KeyBank National Association as Syndication Agent, PNC Bank National Association as Administrative Agent and KeyBanc Capital Markets Inc. and PNC Capital Markets LLC as Joint Lead Arrangers and Joint Bookrunners, dated as of November 12, 2021 is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on November 15, 2021, Commission File Number 1-9172.
10.48*						The North American Coal Corporation Excess Retirement Plan (Amended and Restated Effective January 1, 2020) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on December 18, 2019, Commission File Number 1-9172.
10.50						Revolving Credit Commitment Increase Agreement, dated as of December 10, 2021 is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on December 13, 2021. Commission File Number 1-9172.
10.49*						The NACCO Natural Resources Excess Retirement Plan (Effective January 1, 2025) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on December 17, 2024, Commission File Number 1-9172.
10.51						ESG Amendment to Amended and Restated Credit Agreement, dated as of June 30, 2022, is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on July 7, 2022. Commission File Number 1-9172.
10.50*						Amendment No. 1 to the NACCO Natural Resources Excess Retirement Plan (Effective January 1, 2026) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on December 16, 2025, Commission File Number 1-9172.
10.52						First Amendment to Amended and Restated Credit Agreement, dated as of September 17, 2024, among NACCO Natural Resources Corporation, the guarantors party thereto, the lenders party thereto and PNC Bank, National Association, as administrative agent, is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on September 19, 2024, Commission File Number 1-9172.
10.51						Amended and Restated Credit Agreement by and among The North American Coal Corporation and the Guarantors party thereto and the Lenders party thereto and KeyBank National Association as Syndication Agent, PNC Bank National Association as Administrative Agent and KeyBanc Capital Markets Inc. and PNC Capital Markets LLC as Joint Lead Arrangers and Joint Bookrunners, dated as of November 12, 2021 is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on November 15, 2021, Commission File Number 1-9172.
(19**)						NACCO Industries, Inc. Insider Trading Policy
10.52						Revolving Credit Commitment Increase Agreement, dated as of December 10, 2021 is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on December 13, 2021. Commission File Number 1-9172.
10.53						ESG Amendment to Amended and Restated Credit Agreement, dated as of June 30, 2022, is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on July 7, 2022. Commission File Number 1-9172.
10.54						First Amendment to Amended and Restated Credit Agreement, dated as of September 17, 2024, among NACCO Natural Resources Corporation, the guarantors party thereto, the lenders party thereto and PNC Bank, National Association, as administrative agent, is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on September 19, 2024, Commission File Number 1-9172.
(19)						NACCO Industries, Inc. Insider Trading Policy is incorporated herein by reference to Exhibit 19 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2024, Commission File Number I-9172.
(21**)						Subsidiaries. A list of the subsidiaries of the Company is attached hereto as Exhibit 21.

(23) Consents of experts and counsel.


23.1**						Consents of experts and counsel.
23.2**						Consent of Qualified Person.
23.3**						Consent of Qualified Person.
23.4**						Consent of experts and counsel.

(24) Powers of Attorney.

24.1**						A copy of a power of attorney for John S. Dalrymple is attached hereto as Exhibit 24.1.
24.2**						A copy of a power of attorney for John P. Jumper is attached hereto as Exhibit 24.2.
24.3**						A copy of a power of attorney for Dennis W. LaBarre is attached hereto as Exhibit 24.3.
24.4**						A copy of a power of attorney for W. Paul McDonald is attached hereto as Exhibit 24.4.
24.5**						A copy of a power of attorney for Michael S. Miller is attached hereto as Exhibit 24.5.
24.6**						A copy of a power of attorney for Alfred M. Rankin, Jr. is attached hereto as Exhibit 24.6.
24.7**						A copy of a power of attorney for Matthew M. Rankin is attached hereto as Exhibit 24.7.
24.8**						A copy of a power of attorney for ~~Roger~~Valerie F.Gentile ~~Rankin~~Sachs is attached hereto as Exhibit 24.8.
24.9**						A copy of a power of attorney for ~~Lori~~Robert JS. ~~Robinson~~Shapard is attached hereto as Exhibit 24.9.
24.10**						A copy of a power of attorney for ~~Valerie~~Britton ~~Gentile~~T. ~~Sachs~~Taplin is attached hereto as Exhibit 24.10.
24.11**						A copy of a power of attorney for Robert S. Shapard is attached hereto as Exhibit 24.11.
24.12**						A copy of a power of attorney for Britton T. Taplin is attached hereto as Exhibit 24.12.

7065

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Exhibit Number						Exhibit Description
(31) Rule 13a-14(a)/15d-14(a) Certifications.
31(i)(1)**						Certification of J.C. Butler, Jr. pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act is attached hereto as Exhibit 31(i)(1).
31(i)(2)**						Certification of Elizabeth I. Loveman pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act is attached hereto as Exhibit 31(i)(2).
(32)****						Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed and dated by J.C. Butler, Jr. and Elizabeth I. Loveman.
(95)**						Mine Safety Disclosure Exhibit.
96.1**						Technical Report Summary relating to the Mississippi Lignite Mining Company, effective date as of December 31, 2024.
96.1						Technical Report Summary relating to the Mississippi Lignite Mining Company, effective date as of December 31, 2024, is incorporated herein by reference to Exhibit 96.1 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2024, Commission File Number I-9172.
(97.1)**						NACCO Industries, Inc. Dodd-Frank Clawback Policy
(97.1)						NACCO Industries, Inc. Dodd-Frank Clawback Policy is incorporated herein by reference to Exhibit 97.1 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2024, Commission File Number I-9172.
(99.1**)						Reserve Report of Catapult Mineral Partners.
101.INS						Inline XBRL Instance Document
101.SCH						Inline XBRL Taxonomy Extension Schema Document
101.CAL						Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF						Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB						Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE						Inline XBRL Taxonomy Extension Presentation Linkbase Document
104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)


*						Management contract or compensation plan or arrangement required to be filed as an exhibit pursuant to Item15(b) of this Annual Report on Form 10-K.

**						Filed herewith.

***						Certain confidential information contained in this agreement has been omitted because it (i) is not material and (ii) would be competitively harmful if publicly disclosed.

****						Furnished herewith.

+						Portions of Exhibit have been omitted and filed separately with the Securities and Exchange Commission in reliance on Rule 24b-2 and an Order from the Commission granting the Company's request for confidential treatment dated March 27, 2013. Portions for which confidential treatment has been granted have been marked with three asterisks [***] and a footnote indicating Confidential treatment requested.

++						Portions of Exhibit have been omitted and filed separately with the Securities and Exchange Commission in reliance on Rule 24b-2 and an Order from the Commission granting the Company's request for confidential treatment dated April 2, 2013. Portions for which confidential treatment has been granted have been marked with three asterisks [***] and a footnote indicating Confidential treatment requested.

Item 16. Form 10-K Summary

None.

7166

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

NACCO Industries, Inc.

By:

/s/ Elizabeth I. Loveman

Elizabeth I. Loveman

Senior Vice President and Controller
(principal financial and accounting officer)

March 54, ~~2025~~2026

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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/ J.C. Butler, Jr.	President and Chief Executive Officer (principal executive officer)	March 54, ~~2025~~2026
J.C. Butler, Jr.
/s/ Elizabeth I. Loveman	Senior Vice President and Controller (principal financial and accounting officer)	March 54, ~~2025~~2026
Elizabeth I. Loveman
*John S. Dalrymple	Director	March 54, ~~2025~~2026
John S. Dalrymple
* John P. Jumper	Director	March 54, ~~2025~~2026
John P. Jumper
* Dennis W. LaBarre	Director	March 54, ~~2025~~2026
Dennis W. LaBarre
* W. Paul McDonald	Director	March 54, ~~2025~~2026
W. Paul McDonald
* Michael S. Miller	Director	March 54, ~~2025~~2026
Michael S. Miller
* Alfred M. Rankin, Jr.	Director	March 54, ~~2025~~2026
Alfred M. Rankin, Jr.
* Matthew M. Rankin	Director	March 54, ~~2025~~2026
Matthew M. Rankin
* Roger F. Rankin	Director	March 5, 2025
* Valerie Gentile Sachs	Director	March 4, 2026
Roger F. Rankin
*Lori J. Robinson	Director	March 5, 2025
Lori J. Robinson
* Valerie Gentile Sachs	Director	March 5, 2025
Valerie Gentile Sachs
*Robert S. Shapard	Director	March 54, ~~2025~~2026
Robert S. Shapard
* Britton T. Taplin	Director	March 54, ~~2025~~2026
Britton T. Taplin

* Elizabeth I. Loveman, by signing her name hereto, does hereby sign this Form 10-K on behalf of each of the above named and designated directors pursuant to a Power of Attorney executed by such persons and filed with the Securities and Exchange Commission.

/s/ Elizabeth I. Loveman March 54, ~~2025~~2026 Elizabeth I. Loveman, Attorney-in-Fact

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ANNUAL REPORT ON FORM 10-K

ITEM 8, ITEM 15(a)(1) AND (2), AND ITEM 15(c)

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

FINANCIAL STATEMENTS

FINANCIAL STATEMENT SCHEDULES

YEAR ENDED DECEMBER 31, ~~2024~~2025

NACCO INDUSTRIES, INC.

CLEVELAND, OHIO

F-1

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FORM 10-K

ITEM 15(a)(1) AND (2)

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

The following consolidated financial statements of NACCO Industries, Inc. and Subsidiaries and the reports of our independent registered public accounting firm (PCAOB ID:42) are incorporated by reference in Item 8:

Report of Ernst & Young LLP, Independent Registered Public Accounting Firm — For each of the two years in the period ended December 31, 2024.			F-3
Report of Ernst & Young LLP, Independent Registered Public Accounting Firm — For each of the two years in the period ended December 31, 2025.			F-3
Report of Ernst & Young LLP, Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting — As of December 31, 2024.			F-5
Report of Ernst & Young LLP, Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting — As of December 31, 2025.			F-5
Consolidated Statements of Operations			F-6
Consolidated Statements of Comprehensive (Loss) Income			F-7
Consolidated Balance Sheets			F-8
Consolidated Statements of Cash Flows			F-9
Consolidated Statements of Equity			F-10
Notes to Consolidated Financial Statements			F-11

The following consolidated financial statement schedules of NACCO Industries, Inc. and Subsidiaries are included in Item 15(c):


Schedule II — Valuation and Qualifying Accounts

All other schedules for which provision is made in the applicable accounting regulation of the SEC are not required under the related instructions or are inapplicable, and therefore have been omitted.

F-2

Table of Contents

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of NACCO Industries, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of NACCO Industries, Inc. and subsidiaries (the Company) as of December 31, ~~2024~~2025 and ~~2023~~2024, the related consolidated statements of operations, comprehensive ~~(loss)~~ income, equity and cash flows for each of the two years in the period ended December 31, ~~2024~~2025, and the related notes and financial statement schedule listed in the Index at Item 15(b) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, ~~2024~~2025 and ~~2023~~2024, and the results of its operations and its cash flows for each of the two years in the period ended December 31, ~~2024~~2025, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, ~~2024~~2025, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 54, ~~2025~~2026 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit review committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

F-3

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Unconsolidated subsidiaries – accounting for variable interest entities

Description of the Matter			As discussed in Note 1 and 16 to the consolidated financial statements, certain of the operating coal mines and entities within the ~~NAMining~~Contract Mining segment, collectively referred to as the “Unconsolidated Subsidiaries,” are variable interest entities (VIEs) and are accounted for under the equity method. In each case, NACCO is not the primary beneficiary of the VIE as it does not exercise financial control. Although NACCO owns 100% of the equity and manages the daily operations of the Unconsolidated Subsidiaries, the Company has determined that the equity capital provided by NACCO is not sufficient to adequately finance the ongoing activities or absorb any expected losses without additional support from the customers. The customers have a controlling financial interest and have the power to direct activities that most significantly affect the economic performance of the entities. As a result, the Company is not the primary beneficiary and therefore does not consolidate these entities’ financial position or results of operations. The Company regularly evaluates if there are reconsideration events which could change the Company's conclusion as to whether these entities meet the definition of a VIE and the determination of the primary beneficiary.The income before income taxes associated with these VIEs is reported as Earnings of unconsolidated operations on the Consolidated Statements of Operations, and the Company’s investment is reported on the line Investments in unconsolidated subsidiaries in the Consolidated Balance Sheets.Evaluating the Company’s judgments in determining whether an entity is a VIE and the primary beneficiary of the VIE at formation and reconsideration events requires a high degree of complex auditor judgment. The Company also monitors for reconsideration events relating to the Unconsolidated Subsidiaries, which necessitates on-going critical judgments over whether any such events have arisen that require a re-evaluation of prior accounting judgments.
How We Addressed the Matter in Our Audit			We obtained an understanding, evaluated and tested the design and operating effectiveness of the controls surrounding the Company’s application of the variable interest model and the processes to continually assess the implications of significant transactions and events that could trigger a VIE reconsideration event.For those entities where the Company has determined it is not the primary beneficiary, we evaluated the Company’s accounting for and disclosure of the Unconsolidated Subsidiaries under the equity method in accordance with the generally accepted accounting principles. To test the identification of reconsideration events, we obtained and inspected amendments to the agreements with customers, if any, and evaluated evidence from other parts of the audit to determine if a reconsideration event arose that necessitated a re-evaluation of previous accounting judgments. These procedures included, among others, reading board minutes, inquiring of management about transactions or events that could require a reconsideration of previous consolidation conclusions and obtaining direct confirmation of the total annual support provided in accordance with the contractual arrangements from the customers.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2002.

Cleveland, Ohio

March 54, ~~2025~~2026

F-4

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Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of NACCO Industries, Inc.

Opinion on Internal Control Over Financial Reporting

We have audited NACCO Industries, Inc. and subsidiaries’ internal control over financial reporting as of December 31, ~~2024~~2025, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, NACCO Industries, Inc. and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2024~~2025, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the ~~2024~~2025 consolidated financial statements of the Company and our report dated March 54, ~~2025~~2026 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Cleveland, Ohio

March 54, ~~2025~~2026

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NACCO INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31
	2024		2023
	2025		2024
	(In thousands, except per share data)
Revenues	$	~~237~~277,~~708~~198	$	~~214~~237,~~794~~708
Cost of sales	~~207~~238,~~952~~725		~~200~~207,~~203~~952
Gross profit	2938,~~756~~473		1429,~~591~~756
Earnings of unconsolidated operations	5761,~~476~~823		4957,~~994~~476
Business interruption insurance recoveries	~~13,612~~—		—13,612
Operating expenses
Selling, general and administrative expenses	6977,~~754~~851		6569,~~616~~754
Amortization of intangible assets	~~531~~750		~~2,998~~531
(Gain) loss on sale of assets	(5,146)		221
Gain on sale of assets	(286)		(5,146)
Long-lived asset impairment charge	—		65,887
	78,315		65,139
	65,139		134,722
Operating profit	21,981		35,705
Operating profit (loss)	35,705		(70,137)
Other expense (income)
Interest expense	5,~~566~~754		25,~~460~~566
Interest income	(43,~~428~~052)		(64,~~081~~428)
Closed mine obligations	~~2,381~~457		32,~~585~~381
Gain on equity securities	(1,805)		(1,958)
Loss (gain) on equity securities	726		(1,805)
Other, net	345		(3,985)
Gain on settlement of excess funding liability	(3,590)		—
	2,059		(5,979)
Pension settlement charge	7,804		—
Income (loss) before income tax benefit	33,646		(64,158)
Other, net	738		345
Income tax benefit	(95)		(24,571)
	8,837		2,059
Net income (loss)	$	33,741	$	(39,587)
Income before income tax benefit	13,144		33,646
Earnings (loss) per share:
Income tax benefit	(4,430)		(95)
Basic earnings (loss) per share	$	4.58	$	(5.29)
Net income	$	17,574	$	33,741
Diluted earnings (loss) per share	$	4.55	$	(5.29)
Earnings per share:
Basic weighted average shares outstanding	7,363		7,478
Basic earnings per share	$	2.37	$	4.58
Diluted weighted average shares outstanding	7,411		7,478
Diluted earnings per share	$	2.35	$	4.55
Basic weighted average shares outstanding	7,423		7,363
Diluted weighted average shares outstanding	7,481		7,411

See notes to the Consolidated Financial Statements.

F-6

Table of Contents

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE ~~(LOSS)~~ INCOME

	Year Ended December 31
	2024		2023
	2025		2024
	(In thousands)
Net income (loss)	$	33,741	$	(39,587)
Net income	$	17,574	$	33,741
Other comprehensive (loss) income
Other comprehensive income (loss)
Current period pension and postretirement plan adjustment, net of $205 and $615 tax benefit in 2024 and 2023, respectively	(706)		(2,118)
Current period pension and postretirement plan adjustment, net of $557 tax expense and $205 tax benefit in 2025 and 2024, respectively	1,888		(706)
Pension settlement, net of $417 tax benefit in 2023	—		1,398
Pension settlement, net of $1,771 tax benefit in 2025	6,033		—
Reclassification of pension and postretirement adjustments into earnings, net of $89 and $24 tax benefit in 2024 and 2023, respectively	308		79
Reclassification of pension and postretirement adjustments into earnings, net of $115 and $89 tax benefit in 2025 and 2024, respectively	390		308
Total other comprehensive loss	(398)		(641)
Total other comprehensive income (loss)	8,311		(398)
Comprehensive income (loss)	$	33,343	$	(40,228)
Comprehensive income	$	25,885	$	33,343

See notes to the Consolidated Financial Statements.

F-7

Table of Contents

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31
	2025		2024
	(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents	$	49,708	$	72,833
Trade accounts receivable	42,921		49,706
Accounts receivable from affiliates	6,906		5,793
Prepaid profit sharing	11,529		—

Inventories	63,648		94,608
Assets held for sale	12,774		14,159

Prepaid insurance	5,546		1,740
Other current assets	21,860		25,899
Total current assets	214,892		264,738
Property, plant and equipment, net	287,546		259,457
Intangibles, net	4,725		5,475
Mining supplies inventory	34,795		—
Deferred income taxes	14,001		14,641
Investments in unconsolidated subsidiaries	14,750		14,137

Operating lease right-of-use assets	9,595		9,661
Equity securities	17,696		18,663
Equity method investment in Eiger Resources	33,723		19,147
Other non-current assets	29,505		25,768
Total assets	$	661,228	$	631,687
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	16,060	$	17,721
Accounts payable to affiliates	678		1,826

Current maturities of long-term debt	9,080		4,179
Asset retirement obligations	8,185		9,747
Accrued payroll	19,863		22,663
Excess funding liability	5,450		—

Other current liabilities	10,299		8,752
Total current liabilities	69,615		64,888
Long-term debt	16,815		25,335
Long-term revolving credit agreement	75,000		70,000
Operating lease liabilities	7,950		9,042
Asset retirement obligations	39,516		39,780
Retirement benefit plans	4,558		4,787


Other long-term liabilities	18,531		12,908
Total liabilities	231,985		226,740
Stockholders’ equity
Common stock:
Class A, par value $1 per share, 5,864,134 shares outstanding (2024 - 5,730,470 shares outstanding)	5,864		5,730
Class B, par value $1 per share, convertible into Class A on a one-for-one basis, 1,562,963 shares outstanding (2024 - 1,565,359 shares outstanding)	1,563		1,566
Capital in excess of par value	42,427		34,340
Retained earnings	381,130		373,363
Accumulated other comprehensive loss	(1,741)		(10,052)
Total stockholders’ equity	429,243		404,947
Total liabilities and equity	$	661,228	$	631,687

	December 31
	2024		2023
	(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents	$	72,833	$	85,109
Trade accounts receivable	49,706		37,429
Accounts receivable from affiliates	5,793		7,860
Inventories	94,608		77,000
Assets held for sale	14,159		6,466
Other current assets	27,639		18,134
Total current assets	264,738		231,998
Property, plant and equipment, net	259,457		223,902
Intangibles, net	5,475		6,006
Deferred income taxes	14,641		15,081
Investments in unconsolidated subsidiaries	14,137		12,371
Operating lease right-of-use assets	9,661		8,667
Equity securities	18,663		17,208
Equity method investment in Eiger, LLC	19,147		2,800
Other non-current assets	25,768		21,675
Total assets	$	631,687	$	539,708
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	17,721	$	16,702
Accounts payable to affiliates	1,826		904
Revolving credit agreements	—		10,000
Current maturities of long-term debt	4,179		3,953
Asset retirement obligations	9,747		13,114
Accrued payroll	22,663		17,317
Other current liabilities	8,752		7,996
Total current liabilities	64,888		69,986
Long-term debt	25,335		22,003
Long-term revolving credit agreement	70,000		—
Operating lease liabilities	9,042		8,782
Asset retirement obligations	39,780		39,499
Pension and other postretirement obligations	4,787		5,183
Liability for uncertain tax positions	794		5,795
Other long-term liabilities	12,114		6,120
Total liabilities	226,740		157,368
Stockholders’ equity
Common stock:
Class A, par value $1 per share, 5,730,470 shares outstanding (2023 - 5,882,845 shares outstanding)	5,730		5,883
Class B, par value $1 per share, convertible into Class A on a one-for-one basis, 1,565,359 shares outstanding (2023 - 1,565,819 shares outstanding)	1,566		1,566
Capital in excess of par value	34,340		28,672
Retained earnings	373,363		355,873
Accumulated other comprehensive loss	(10,052)		(9,654)
Total stockholders’ equity	404,947		382,340
Total liabilities and equity	$	631,687	$	539,708

See notes to the Consolidated Financial Statements.

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NACCO INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31
	2024		2023
	2025		2024
	(In thousands)
Operating Activities
Net income (loss)	$	33,741	$	(39,587)
Net income	$	17,574	$	33,741
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	2425,~~652~~277		2924,~~387~~652
Amortization of deferred financing fees	~~619~~764		~~505~~619
Deferred income taxes	~~1,517~~58		~~(21~~1,~~114)~~517
Stock-based compensation	58,~~832~~280		5,~~157~~832
(Gain) loss on sale of assets	(5,146)		221
Gain on sale of assets	(286)		(5,146)
Inventory impairment charges	96,~~643~~986		79,~~514~~643
Long-lived asset impairment charge	—		65,887
Pension settlement charge	7,804		—
Other	(37,~~971)~~242		~~968~~(3,971)
Working capital changes:
Changes in operating assets and liabilities:
Accounts receivable	~~(11~~2,~~725)~~916		2(11,~~519~~725)
Inventories	(2711,~~250~~439)		(1227,~~971~~250)
Other current assets	(85,~~677~~177)		(18,~~904~~677)
Accounts payable	12,~~955~~668		31,~~148~~955
Income taxes receivable/payable	(~~148~~2,935)		~~14,996~~(148)
Other current liabilities	1(8,~~247~~823)		~~(236)~~1,247
Net cash provided by operating activities	2250,~~289~~909		5422,~~490~~289
Investing Activities
Expenditures for property, plant and equipment	(5448,~~706~~625)		(4554,~~408~~706)
Acquisition of mineral interests	(~~713~~4,661)		(~~36,714~~713)
Proceeds from the sale of assets	~~822~~2,799		~~561~~822
Equity method investment	(16,~~556~~702)		(316,~~464~~556)
Proceeds from the sale of private company equity units	—		3,574
Return of equity method investment	3,295		—
Other	(~~139~~282)		(~~146~~139)
Net cash used for investing activities	(7164,~~292~~176)		(8171,~~597~~292)
Financing Activities
Net additions to revolving credit agreement	605,000		1060,000
Additions to long-term debt	624		5,232
Reductions to long-term debt	(4,643)		(4,914)
Reductions to long-term debt	(4,914)		(4,209)
(Reductions) additions to note payable to affiliate	(346)		624
Debt issuance costs	~~(2,415)~~—		—(2,415)
Cash dividends paid	(67,~~624~~335)		(6,~~452~~624)
Purchase of treasury shares	(92,~~944~~534)		(39,~~103~~944)
Net cash provided by financing activities	36,727		1,468
Net cash (used for) provided by financing activities	(9,858)		36,727
Cash and Cash Equivalents
Total decrease for the year	(1223,~~276~~125)		(2512,~~639~~276)
Balance at the beginning of the year	8572,~~109~~833		~~110~~85,~~748~~109
Balance at the end of the year	$	7249,~~833~~708	$	8572,~~109~~833

See notes to the Consolidated Financial Statements.

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NACCO INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

	Class A Common Stock		Class B Common Stock		Capital in Excess of Par Value		Retained Earnings		Accumulated Other Comprehensive (Loss) Income		Total Stockholders' Equity
	(In thousands, except per share data)
Balance, January 1, 2023	$	5,783	$	1,566	$	23,706	$	404,924	$	(9,013)	$	426,966
Balance, January 1, 2024	$	5,883	$	1,566	$	28,672	$	355,873	$	(9,654)	$	382,340
Stock-based compensation	191		—		4,966		—		—		5,157
Purchase of treasury shares	(91)		—		—		(3,012)		—		(3,103)
Net loss	—		—		—		(39,587)		—		(39,587)
Cash dividends on Class A and Class B common stock: $0.8600 per share	—		—		—		(6,452)		—		(6,452)
Current period other comprehensive income, net of tax	—		—		—		—		(2,118)		(2,118)
Pension settlement, net of tax	—		—		—		—		1,398		1,398
Reclassification adjustment to net income, net of tax	—		—		—		—		79		79
Balance, December 31, 2023	$	5,883	$	1,566	$	28,672	$	355,873	$	(9,654)	$	382,340
Stock-based compensation	164		—		5,668		—		—		5,832
Purchase of treasury shares	(317)		—		—		(9,627)		—		(9,944)
Net income	—		—		—		33,741		—		33,741
Cash dividends on Class A and Class B common stock: $0.9000 per share	—		—		—		(6,624)		—		(6,624)
Current period other comprehensive income, net of tax	—		—		—		—		(706)		(706)
Reclassification adjustment to net income, net of tax	—		—		—		—		308		308
Balance, December 31, 2024	$	5,730	$	1,566	$	34,340	$	373,363	$	(10,052)	$	404,947
Stock-based compensation	193		—		8,087		—		—		8,280
Purchase of treasury shares	(62)		—		—		(2,472)		—		(2,534)
Conversion of Class B to Class A shares	3		(3)		—		—		—		—
Net income	—		—		—		17,574		—		17,574
Cash dividends on Class A and Class B common stock: $0.9850 per share	—		—		—		(7,335)		—		(7,335)
Current period other comprehensive income, net of tax	—		—		—		—		1,888		1,888
Pension settlement, net of tax	—		—		—		—		6,033		6,033
Reclassification adjustment to net income, net of tax	—		—		—		—		390		390
Balance, December 31, 2025	$	5,864	$	1,563	$	42,427	$	381,130	$	(1,741)	$	429,243

See notes to the Consolidated Financial Statements.

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Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)

NOTE 1—Principles of Consolidation and Nature of Operations

The accompanying Consolidated Financial Statements include the accounts of NACCO Industries, Inc.® (NACCO) and its wholly owned subsidiary, NACCO Natural Resources Corporation® (NACCO Natural Resources, and with NACCO collectively, the Company, we, our or us). NACCO Natural Resources brings natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through our robust portfolio of businesses. We operate under three business segments: Utility Coal Mining, ~~North~~Contract ~~American~~ Mining® ~~(NAMining)~~ and Minerals ~~Management~~and Royalties. The Utility Coal Mining segment, ~~operates~~operated by North American Coal®, manages surface coal mines that are exclusive, long-term fuel providers for power generation companies. The ~~NAMining~~Contract Mining segment, isoperated aby ~~trusted~~North ~~mining~~American ~~partner~~Mining®, ~~for~~is ~~producers~~a leading provider of ~~aggregates,~~a ~~activated~~broad ~~carbon,~~range ~~lithium~~of ~~and~~specialized, ~~other~~long-term ~~industrial~~contract ~~minerals.~~mining services. The Minerals ~~Management~~and Royalties 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~~royalty ~~mitigation~~interests ~~solutions as well as comprehensive reclamation~~ and ~~restoration~~other ~~construction~~related ~~services~~investments. ~~In addition, ReGen Resources is pursuing opportunities to develop new power generation resources.~~

WeIn ~~have~~addition ~~items~~to ~~not~~the ~~directly~~reportable ~~attributable~~segments todiscussed aabove, ~~reportable~~we ~~segment~~also operate other businesses that are not ~~included~~currently ~~in the~~ reported ~~financial~~as ~~results~~separate ~~of the operating segment~~segments. These ~~items~~businesses ~~primarily~~complement ~~include~~our ~~administrative~~existing ~~costs~~operations ~~related~~and tosupport ~~public~~our ~~company~~long-term ~~reporting~~growth ~~requirements,~~strategic ~~including~~objectives. ~~management~~Mitigation ~~and~~Resources ~~board compensation, and the financial results~~ of ~~Bellaire~~North ~~Corporation~~America® (~~Bellaire),~~ Mitigation Resources,) ~~ReGen~~provides ~~Resources~~natural ~~and~~resource ~~other~~restoration ~~developing~~and ~~businesses.~~reclamation ~~Bellaire~~services ~~manages~~that ~~our~~include ~~long-term~~stream ~~liabilities~~and ~~related~~wetland tomitigation ~~former Eastern U~~solutions.S. ~~underground~~ReGen ~~mining~~Resources ~~activities.~~is ~~Intercompany~~pursuing ~~accounts~~opportunities

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