nacco-20211231
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
(Mark One)
For the fiscal year ended December 31, 2021
or
Commission File No. 1-9172
NACCO INDUSTRIES, INC.
(Exact name of registrant as specified in its charter)
(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 NC New York Stock Exchange
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 ̈Noþ
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 ̈Noþ
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.
Yesþ 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).
Yesþ 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.
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. ☑
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, 2021 (the last business day of the registrant's most recently completed second fiscal quarter): $109,032,630
Number of shares of Class A Common Stock outstanding at February 18, 2022: 5,616,768
Number of shares of Class B Common Stock outstanding at February 18, 2022: 1,566,413
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Company's Proxy Statement for its 2022 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 20
Item 1B. UNRESOLVED STAFF COMMENTS 31
Item 2. PROPERTIES 31
Item 3. LEGAL PROCEEDINGS 43
Item 4. MINE SAFETY DISCLOSURES 43
PART II.
Item 6. SELECTED FINANCIAL DATA 44
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 60
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 60
Item 9A. CONTROLS AND PROCEDURES 60
Item 9B. OTHER INFORMATION 60
Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS 60
PART III.
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 61
Item 11. EXECUTIVE COMPENSATION 61
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES 61
PART IV.
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 62
SIGNATURES 69
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA F-1
Table of Contents
PART I
Item 1. BUSINESS
General
NACCO Industries, Inc.® (“NACCO” or the “Company”) brings natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through its robust portfolio of NACCO Natural Resources businesses. The Company operates under three business segments: Coal Mining, North American Mining ("NAMining") and Minerals Management. The Coal Mining segment operates surface coal mines for power generation companies and an activated carbon producer. The NAMining segment is a trusted mining partner for producers of aggregates, lithium and other minerals. The Minerals Management segment, which includes the Catapult Mineral Partners (“Catapult”) business, acquires and promotes the development of mineral interests. In addition, Mitigation Resources of North America® (“Mitigation Resources”) provides stream and wetland mitigation solutions.
The Company has items not directly attributable to a reportable segment that are not included as part of the measurement of segment operating profit, which primarily includes administrative costs related to public company reporting requirements at the parent company and the financial results of Mitigation Resources and Bellaire Corporation ("Bellaire"). Bellaire manages the Company’s long-term liabilities related to former Eastern U.S. underground mining activities.
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
During 2021, the Company launched a new branding campaign. The new branding creates a unified identity and underscores NACCO’s commitment to all of its businesses, while focusing on the execution of its two key strategies – Protect the Core and Grow and Diversify. NACCO’s portfolio of businesses now operates under the umbrella of NACCO Natural Resources. The new branding provides each business with its own unique identity that can easily be linked back to the NACCO legacy brand and includes new websites for each business, including NACCO Natural Resources, new business-specific logos and a new tagline “Bringing Natural Resources to Life”.
The Company is pursuing growth and diversification by strategically leveraging its core mining and natural resources management skills to build a strong portfolio of affiliated businesses. Management continues to be optimistic about the long-term outlook for growth in the NAMining and Minerals Management segments and in the Company's Mitigation Resources business. Each of these businesses continues to expand its pipeline of potential new projects with opportunities for growth and diversification.
NAMining is pursuing growth and diversification by expanding the scope of its business development activities to include potential customers who require a broad range of minerals and materials and by leveraging the Company’s core mining skills to expand the range of contract mining services it provides. The goal is to build NAMining into a leading provider of contract mining services for customers who produce a wide variety of minerals and materials. The Company believes NAMining can grow to be a substantial contributor to operating profit, delivering unlevered after-tax returns on invested capital in the mid-teens as this business model matures and achieves significant scale, but the pace of achieving these objectives will be dependent on the mix and scale of new projects.
The Minerals Management segment continues to grow and diversify by selectively acquiring mineral and royalty interests in the United States, in a market and price environment that the Company believes remains well-aligned with its strategy and objectives. The Minerals Management segment will benefit from the continued development of its mineral properties without additional capital investment, as all further development costs are borne entirely by third-party producers who lease the minerals. The Company believes this business model can deliver substantial operating margins over the life of a reserve without the costs and risk that traditional oil and gas companies bear for the cost of exploration, production and/or development. Catapult, the Company’s business unit focused on managing and expanding the Company’s portfolio of oil and gas mineral and royalty interests, has developed a strong network to source and secure new acquisitions, and has several potential acquisitions under review. The goal is to construct a diversified portfolio of high-quality oil and gas mineral and royalty interests in the United States that deliver near-term cash flow yields and long-term projected growth. The Company believes this business will provide unlevered after-tax returns on invested capital in the low-to-mid-teens as the portfolio of reserves and mineral interests grows and this business model matures.
Mitigation Resources continues to expand its business, which creates and sells stream and wetland mitigation credits and provides services to those engaged in permittee-responsible mitigation. This business offers an opportunity for growth and diversification in an industry where the Company has substantial knowledge and expertise and a strong reputation. The Mitigation Resources business has achieved several early successes and is positioned for additional growth. The Company's
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goal is to grow Mitigation Resources into one of the ten largest U.S. providers of mitigation solutions, largely focused on streams and wetlands, initially in the southeast United States. While this business is in the early stages of development, the Company believes that Mitigation Resources can provide solid rates of return as this business matures.
The Company also continues to pursue activities which can strengthen the resiliency of its existing coal mining operations. The Company remains focused on managing coal production costs and maximizing efficiencies and operating capacity at mine locations to help customers with management fee contracts be more competitive. These activities benefit both customers and the Company's Coal Mining segment, as fuel cost is a significant driver for power plant dispatch. Increased power plant dispatch results in increased demand for coal by the Coal Mining segment's customers. Fluctuating natural gas prices and availability of renewable energy sources, such as wind and solar, affect the amount of electricity dispatched from coal-fired power plants. Coal and natural gas traditionally have been the two largest sources of electricity generation in the United States. In many areas of the country, these two fuels compete to supply electricity based on their relative costs. U.S. natural gas prices have been more volatile than coal prices, so the cost of natural gas often determines the relative share of generation provided by natural gas and coal. Between 2015 and 2020, the cost of natural gas delivered to electric generators remained relatively low and stable. During 2021, however, natural gas prices were much higher than in recent years, generally resulting in increased dispatch of coal-fired power plants.
The Company continues to look for opportunities to expand its coal mining business where it can apply its management fee business model to assume operation of existing surface coal mining operations in the United States. However, opportunities are very limited in the current environment. In addition, the political and regulatory environment is not receptive to development of new coal-fired power generation projects which would create opportunities to build and operate new coal mines.
The Company is committed to maintaining a conservative capital structure as it continues to grow and diversify, while avoiding unnecessary risk. Strategic diversification will generate cash that can be re-invested to strengthen and expand the businesses. In all of its business endeavors, the Company continues to maintain the highest levels of customer service and operational excellence, with an unwavering focus on safety, environmental stewardship and people. The Company is passionately committed to working hard, doing what’s right, and bringing America's natural resources to life.
Business Developments
Coal Mining Segment
Effective September 30, 2021, the contract mining agreement between Bisti Fuels Company, LLC (“Bisti”) and its customer, Navajo Transitional Energy Company ("NTEC") was terminated. As required under the agreement, NTEC paid the Company a termination fee of $10.3 million. As of October 1, 2021, NTEC assumed control and responsibility for operation and all reclamation of the Navajo Mine.
The Coteau Properties Company (“Coteau”) operates the Freedom Mine in North Dakota. All coal production from the Freedom Mine is delivered to Basin Electric Power Cooperative (“Basin Electric”). Basin Electric utilizes the coal at the Great Plains Synfuels Plant (the “Synfuels Plant”), Antelope Valley Station and Leland Olds Station. The Synfuels Plant is a coal gasification plant, owned by Dakota Gasification Company (“Dakota Gas’), a subsidiary of Basin Electric, that manufactures synthetic natural gas and produces fertilizers, solvents, phenol, carbon dioxide, and other chemical products for sale. During 2020, Basin Electric informed Coteau that it is considering changes that may result in modifications to its Synfuels Plant that could potentially reduce or eliminate coal requirements at the Synfuels Plant. During August 2021, Bakken Energy (“Bakken”) and Basin Electric signed a non-binding term sheet to transfer ownership of the assets of Dakota Gas to Bakken. Bakken stated the closing date is expected to be April 1, 2023. As part of the term sheet between Basin Electric and Bakken, Basin Electric indicated that the Synfuels Plant will continue existing operations through 2025. The closing is subject to the satisfaction of specified conditions. Basin Electric is also considering other options for the Synfuels Plant if the transaction with Bakken does not close. Basin Electric indicated that if it decides to proceed with any changes that could reduce or eliminate the use of coal, the feedstock change is not expected to occur before 2026.
The Falkirk Mining Company ("Falkirk") operates the Falkirk Mine in North Dakota. Falkirk is the sole supplier of lignite coal to the Coal Creek Station power plant pursuant to a contract under which Falkirk also supplies approximately 0.3 million tons of lignite coal per year to Spiritwood Station power plant. Coal Creek Station and Spiritwood Station are owned by Great River Energy (“GRE”). In May 2020, GRE announced its intent to sell or retire Coal Creek Station and modify Spiritwood Station to be fueled by natural gas.
During June 2021, GRE entered into an agreement to sell Coal Creek Station and the adjacent high-voltage direct current transmission line to Bismarck, North Dakota-based Rainbow Energy Center, LLC (“Rainbow Energy”) and its affiliates. The
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closing of this sale is subject to the satisfaction of certain conditions and presently, the transaction is expected to close in the second quarter of 2022.
Upon completion of the sale of Coal Creek Station, the existing Coal Sales Agreement, the existing Mortgage and Security Agreement and the existing Option Agreement between GRE and Falkirk will terminate. Falkirk and GRE have entered into a termination and release of claims agreement. Upon completion of the sale of Coal Creek Station, GRE will pay Falkirk $14.0 million in cash, as well as transfer ownership of an office building located in Bismarck, North Dakota, and convey membership units in Midwest AgEnergy to The North American Coal Corporation® (“NACoal”), a wholly-owned subsidiary of NACCO. NACCO currently holds a $5.0 million investment in Midwest AgEnergy, which operates two ethanol facilities in North Dakota.
If GRE's efforts to sell the power plant are successful, a new Coal Sales Agreement (“CSA”) between Falkirk and Rainbow Energy will become effective and Falkirk will supply all coal requirements of Coal Creek Station concurrent with Rainbow Energy’s acquisition of the power plant. Falkirk will no longer make any coal deliveries to GRE’s Spiritwood Station. Falkirk will be paid a management fee and Rainbow Energy will be responsible for funding all mine operating costs and directly or indirectly providing all of the capital required to operate the mine. The CSA specifies that Falkirk will perform final mine reclamation, which will be funded in its entirety by Rainbow Energy. The initial production period is expected to run ten years from the effective date of the CSA, but the CSA may be extended or terminated early under certain circumstances. If Rainbow Energy terminates the CSA and closes Coal Creek Station before 2027, Falkirk will be entitled to an additional payment from GRE under the terms of the termination and release of claims agreement. The additional payment amount ranges from $8 million if the closure occurs before 2024 to $2 million if the closure occurs in 2026. To support the transfer to new ownership, Falkirk has agreed to a reduction in the current per ton management fee from the effective date of the new CSA through May 31, 2024. After May 31, 2024, the per ton management fee increases to a higher base in line with current fee levels, and thereafter adjusts annually according to an index which tracks broad measures of U.S. inflation.
If GRE’s efforts to sell the power plant are not successful and GRE elects to prematurely close Coal Creek Station, the early termination of the CSA would have a material adverse effect on the Company's business, financial condition and results of operations.
The Sabine Mining Company (“Sabine”) operates the Sabine Mine in Texas. All production from Sabine is delivered to Southwestern Electric Power Company's (“SWEPCO”) Henry W. Pirkey Plant (the “Pirkey Plant”). SWEPCO is an American Electric Power (“AEP”) company. During 2020, AEP announced its intent to retire the Pirkey Plant in 2023. SWEPCO expects deliveries from Sabine to continue until the first quarter of 2023 at which time Sabine expects to begin final reclamation. Funding for mine reclamation is the responsibility of SWEPCO.
During 2020, Caddo Creek Resources Company, LLC (“Caddo Creek”) ceased all mining and delivery of lignite and commenced mine reclamation. Funding for mine reclamation is the responsibility of a subsidiary of Advanced Emissions Solutions (“AES”). Caddo Creek entered into a contract with a subsidiary of AES to perform the required mine reclamation. The reclamation at Caddo Creek is expected to be substantially complete during the first half of 2022.
During 2020, the contract mining agreement between Camino Real Fuels, LLC (“Camino Real”) and its customer, Dos Republicas Coal Partnership (“DRCP”), terminated and resulted in mine closure. Funding for mine reclamation is the responsibility of DRCP.
NAMining Segment
In the third quarter of 2021, NAMining entered into contracts with a new customer to perform all mining operations at two sand and gravel quarries located in Texas and Arkansas. The initial term of each contract is two years, and one of the contracts automatically extends an additional two years provided NAMining is not in default under that contract. In the second quarter of 2021, NAMining entered into a one-year mining services contract with an existing customer for a sand and gravel quarry in Indiana. In the first quarter of 2021, NAMining entered into a 15-year mining services contract with a new customer at a limestone quarry in Central Florida. NAMining will operate two smaller draglines at this quarry while it relocates and commissions a larger dragline that will increase production capacity. The relocated dragline is anticipated to be commissioned in the second half of 2022. During 2021, NAMining also amended a contract with a current customer to provide additional services at a limestone quarry in Florida.
In addition, NAMining will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.
Thacker Pass is owned by Lithium Nevada Corp., a subsidiary of Lithium Americas Corp. (TSX: LAC) (NYSE: LAC). Lithium Americas Corp. owns the lithium reserves at Thacker Pass and will be responsible for the processing and sale of the lithium
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produced. At maturity, the Thacker Pass management fee contract is expected to deliver fee income similar to a mid-sized management fee coal mine.
Minerals Management Segment
During 2021 and 2020, the Minerals Management segment acquired additional mineral interests, primarily in the Eagle Ford and Permian Basins in Texas. During the second quarter of 2021, the Minerals Management segment, through its Catapult business, acquired a combination of mineral and overriding royalty interests in the Eagle Ford Basin, which includes approximately 14.1 thousand gross acres and 1.7 thousand net royalty acres, for an initial payment of $4.7 million. Under the terms of the transaction, Catapult could make additional payments for each additional well developed on the acquired assets during 2022 of up to a maximum of $0.6 million. Catapult also completed a small acquisition of royalty interests in the Delaware Basin during 2021 for a purchase price of $0.3 million. Minerals Management intends to continue to make future acquisitions of mineral and royalty interests that meet the Company’s acquisition criteria as part of its growth strategy.
Operations
Coal Mining Segment
The Coal Mining segment, NACoal, operates surface coal mines under long-term contracts with power generation companies and an activated carbon producer pursuant to a service-based business model. Coal is surface mined in North Dakota, Texas, Mississippi and Louisiana. Through September 30, 2021, the Company provided contract mining services on the Navajo Nation in New Mexico. Each mine is fully integrated with its customer's operations.
During 2021, the Company's operating coal mines were: Bisti, Coteau, Coyote Creek Mining Company, LLC (“Coyote Creek”), Demery Resources Company, LLC (“Demery”), Falkirk, Mississippi Lignite Mining Company (“MLMC”) and Sabine.
Coteau, Coyote, Falkirk, MLMC and Sabine supply lignite coal for power generation. Demery supplies lignite coal for the production of activated carbon products. Each mine is the exclusive supplier of coal to its customers' facilities. Each of these mines delivers its coal production to adjacent or nearby power plants, synfuels plants or an activated carbon processing facility under long-term supply contracts. MLMC’s lignite sales agreement contains a minimum annual take provision; all other coal supply contracts are requirements contracts under which earnings can fluctuate based on customer requirements. Certain coal supply contracts can be terminated early, which would result in a reduction to future earnings.
At all operating coal mines other than MLMC, the Company is paid a management fee per ton of coal or heating unit (MMBtu) delivered. Each contract specifies the indices and mechanics by which fees change over time, generally in line with broad measures of U.S. inflation. The customers are responsible for funding all mine operating costs, including final mine reclamation, and directly or indirectly provide all of the capital required to build and operate the mine. This contract structure eliminates the Company's exposure to spot coal market price fluctuations while providing income and cash flow with minimal capital investment. Other than at Coyote Creek, debt financing provided by or supported by the customers is without recourse to NACCO and NACoal. See Note 17 to the Consolidated Financial Statements in this Form 10-K for further discussion of Coyote Creek's guarantees.
All operating coal mines other than MLMC meet the definition of a variable interest entity (“VIE”). In each case, NACCO is not the primary beneficiary of the VIE as it does not exercise financial control; therefore, NACCO does not consolidate the results of these operations within its financial statements. Instead, these contracts are accounted for as equity method investments. The income before income taxes associated with these VIEs is reported as Earnings of unconsolidated operations on the Consolidated Statements of Operations, and the Company’s 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 the NACCO consolidated U.S. tax return; therefore, the income tax expense line on the Consolidated Statements of Operations includes income taxes related to these entities. See Note 17 to the Consolidated Financial Statements in this Form 10-K for further information on the Unconsolidated Subsidiaries.
The Company performs contemporaneous reclamation activities at each mine in the normal course of operations. Under all of the Unconsolidated Subsidiaries’ contracts, the customer has the obligation to fund final mine reclamation activities. Under certain contracts, the Unconsolidated Subsidiary holds the mine permit and is therefore responsible for final mine reclamation activities. To the extent the Unconsolidated Subsidiary performs such final reclamation, it is compensated for providing those services in addition to receiving reimbursement from customers for costs incurred.
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Caddo Creek met the definition of a VIE prior to the cessation of mining on September 30, 2020. The terms of the contract to perform mine reclamation contain a fixed-price component and therefore, Caddo Creek has been consolidated within the Company's financial statements since October 1, 2020.
The MLMC contract is the only operating coal contract in which the Company is responsible for all operating costs, capital requirements and final mine reclamation; therefore, MLMC is consolidated within NACCO’s financial statements. MLMC sells coal to its customer at a contractually agreed-upon price which adjusts monthly, primarily based on changes in the level of established indices which reflect general U.S. inflation rates. Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred. As diesel fuel is heavily weighted among the indices used to determine the coal sales price, fluctuations in diesel fuel prices can result in significant fluctuations in earnings at MLMC.
MLMC delivers coal to the Red Hills Power Plant in Ackerman, Mississippi. The Red Hills Power Plant supplies electricity to the Tennessee Valley Authority ("TVA") under a long-term Power Purchase Agreement ("PPA"). MLMC’s contract with its customer runs through 2032. TVA’s power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables. The decision of which power plants to dispatch is determined by TVA. Reduction in dispatch of the Red Hills Power Plant will result in reduced coal deliveries and earnings at MLMC.
See “Item 2. Properties" on page 31 in this Form 10-K for discussion of the Company's mineral resources and mineral reserves.
NAMining Segment
The NAMining segment provides value-added contract mining and other services for producers of aggregates, lithium and other minerals. The segment is a primary platform for the Company’s growth and diversification of mining activities outside of the coal industry. NAMining provides contract mining services for independently owned mines and quarries, creating value for its customers by performing the mining aspects of its customers’ operations. This allows customers to focus on their areas of expertise: materials handling and processing, product sales and distribution. NAMining historically operated primarily at limestone quarries in Florida, but is focused on expanding outside of Florida, mining materials other than limestone and expanding the scope of mining operations provided to its customers. As of December 31, 2021, NAMining operates mines in Florida, Texas, Arkansas and Indiana and will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.
NAMining utilizes both fixed price and management fee contract structures. Certain of the entities within the NAMining segment are VIEs and are accounted for under the equity method as Unconsolidated Subsidiaries. See Note 17 to the Consolidated Financial Statements in this Form 10-K for further information on the Unconsolidated Subsidiaries.
Minerals Management Segment
The Minerals Management segment derives income primarily by leasing its royalty and mineral interests to third-party exploration and production companies, and, to a lesser extent, other mining companies, granting them the rights to explore, develop, mine, produce, market and sell gas, oil, and coal in exchange for royalty payments based on the lessees' sales of those minerals.
The acquisition criteria for building a blended portfolio of mineral and royalty interests includes (i) new wells anticipated to come online within one to two years of investment, (ii) areas with forecasted future development within five years after acquisition, or (iii) existing producing wells further along the decline curve that will generate stable cash flow. In addition, acquisitions should extend the geographic footprint to diversify across multiple basins with a preliminary focus on the more oil-rich Permian basin and a secondary focus on other diversifying basins to increase regional exposure. While the current focus is on the acquisition of mineral and royalty interests, the Company would also consider investments in overriding royalty interests, non-participating royalty interests or non-operated working interests under certain circumstances.The current acquisition strategy does not contemplate any near-term working interest investments in which the Company would act as the operator.
Total consideration for the 2021 and 2020 acquisitions of mineral and royalty interests was $5.3 million and $14.2 million, respectively. The 2021 acquisitions include 20.6 thousand gross acres and 1.8 thousand net royalty acres. The 2020 acquisitions include 65.5 thousand gross acres and 1.2 thousand net royalty acres. Total mineral and royalty interests include approximately 127.8 thousand gross acres and 59.9 thousand net royalty acres at December 31, 2021.
The Company’s legacy royalty and mineral interests are located in Ohio (Utica and Marcellus shale natural gas), Louisiana (Haynesville shale and Cotton Valley formation natural gas), Texas (Cotton Valley and Austin Chalk formation natural gas),
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Mississippi (coal), Pennsylvania (coal, coalbed methane and Marcellus shale natural gas), Alabama (coal, coalbed methane and natural gas) and North Dakota (coal, oil and natural gas). The majority of the Company’s legacy reserves were acquired as part of its historical coal mining operations.
The Minerals Management segment owns royalty interests, mineral interests, nonparticipating royalty interests, and overriding royalty interests.
•Royalty Interest. Royalty interests generally result when the owner of a mineral interest leases the underlying minerals to an exploration and production company pursuant to an oil and gas lease. Typically, the resulting royalty interest is a cost-free percentage of production revenues for minerals extracted from the acreage. A holder of royalty interests is generally not responsible for capital expenditures or lease operating expenses, but may be responsible for certain post-production expenses, and typically have no environmental liability. Royalty interests expire upon the expiration of the oil and gas lease.
•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.
•Overriding Royalty Interest (“ORRIs”). ORRIs are created by carving out the right to receive royalties from a working interest. Like royalty interests, ORRIs do not confer an obligation to make capital expenditures or pay for lease operating expenses and have limited environmental liability, however ORRIs may be calculated net of post-production expenses, depending on how the ORRI is structured. ORRIs that are carved out of working interests are linked to the same underlying oil and gas lease that created the working interest, and therefore, such ORRIs are typically subject to expiration upon the expiration or termination of the oil and gas lease.
The Company may own more than one type of mineral and royalty interest in the same tract of land. For example, where the Company owns an ORRI in a lease on the same tract of land in which it owns a mineral interest, the ORRI in that tract will relate to the same gross acres as the mineral interest in that tract.
The Minerals Management segment will benefit from the continued development of its mineral properties without the need for investment of additional capital once mineral and royalty interests have been acquired. The Minerals Management segment does not have any investments under which it would be required to bear the cost of exploration, production or development.
See “Item 2. Properties" on page 31 in this Form 10-K for discussion of the Company's proved reserves.
Customers
The principal customers of the Coal Mining segment are electric utilities, an independent power provider and a producer of activated carbon.
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 royalty owner and non-operator, the Company has 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 on which such volumes are marketed and sold.
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In 2021 and 2020, two customers individually accounted for more than 10% of consolidated revenues. The following represents the revenue attributable to each of these entities as a percentage of consolidated revenues for those years:
Percentage of Consolidated Revenues
Coal Mining customer 43 % 55 %
NAMining customer 19 % 19 %
The loss of either of these customers could have a material adverse effect on the results of operations attributable to the applicable segment and on the Company's consolidated results of operations.
In addition to the customers listed above, the Company has certain subsidiaries that meet the definition of a VIE; therefore, NACCO does not consolidate the results of these operations within its financial statements. Instead, these contracts are accounted for as equity method investments. For the year ended December 31, 2021, the Coal Mining segment derived approximately 68% of the Earnings of Unconsolidated Operations from two customers, Basin Electric and GRE. The loss of either of these contracts could have a material adverse effect on the Earnings of Unconsolidated Operations of the Coal Mining segment and a material adverse effect on the Company's Consolidated Statements of Operations.
Competition
The Company's coal mines are directly adjacent to the 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 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. In addition, it competes with subsidized sources of energy, primarily wind and solar. Among the factors that affect competition are the price and availability of oil and natural gas, environmental and related political considerations, the time and expenditures required to develop new energy sources, the cost of transportation, the cost of compliance with governmental regulations, the impact of federal and state energy policies, the impact of subsidies on renewable pricing and the Company's customers' dispatch decisions, which may also take into account carbon dioxide emissions. The ability of the Coal Mining segment to maintain comparable levels of coal production at existing facilities and to market and develop its reserves will depend upon the interaction of these factors.
Electricity generating units are chosen to run primarily based on operating costs, of which fuel costs account for the largest share. Natural gas-fired power plants have the most potential to continue to displace coal-fired electric baseload power generation in the near term. There also continues to be an increase in the amount of electricity generated by wind and solar. Fluctuations in natural gas prices and the availability of renewable generation, particularly wind, can contribute to changes in power plant dispatch and customer demand for coal. The significant increase in natural gas prices in 2021 compared to natural gas prices in 2020 contributed to an increase in customer power plant dispatch and coal deliveries in 2021. Sustained higher natural gas prices could lead to increased demand for coal and positively affect Coal Mining segment results. Over the longer term, the Company continues to believe that customer demand will remain pressured by continuing increases in subsidized renewable generation sources, particularly wind. Federal and state mandates for increased use of electricity derived from renewable energy sources have also negatively affected demand for coal. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, make alternative fuel sources competitive with coal. The Taxpayer Certainty and Disaster Tax Relief Act of 2020 extended the production tax credit (“PTC”) under Section 45 of the Internal Revenue Code and the investment tax credit (“ITC”) under Section 48 of the Code. The PTC for wind was extended at the current phase-out level (60% of the otherwise allowable credits) for facilities where construction began in 2021. The ITC for solar was extended at 26% for energy property where construction begins in 2021-2022 and at 22% where construction begins in 2023-2025. Solar energy property placed in service after December 31, 2025 will receive a 10% ITC. Environmental, social and governance considerations can also have an impact on power plant dispatch and demand for coal.
Based on industry information, the Company believes it was one of the ten largest coal producers in the U.S. in 2021 based on total coal tons produced.
NAMining faces competition from producers of aggregates, lithium or other minerals that choose to self-perform mining operations and from other mining companies.
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In the Minerals Management segment, the oil and gas industry is intensely competitive; the Company primarily competes 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 the Company’s 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 the Company can, which would adversely affect its 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 its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because the Company has fewer financial resources than many companies in the oil and gas industry, the Company may be at a disadvantage in bidding for oil and natural gas properties.
Seasonality
The Company has experienced limited variability in its 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 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.
The NAMining 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 pandemics, all of which can result in variations in demand for aggregates.
In the Minerals Management 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 the Company's 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, the Company's lessees' willingness and ability to incur well-development and other operating costs, and changes in the availability and continuing development of infrastructure.
Human Capital
As of December 31, 2021, the Company and its subsidiaries had approximately 1,600 employees, including approximately 1,100 employees at the Company’s unconsolidated mining operations, none of which are represented by a collective bargaining agreement. NACCO believes it has good relations with its employees.
Market-Based Compensation: NACCO believes its employees are critical to its success and invests in its 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. The Company provides 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 employee, spouse and dependents;
•Flexible spending accounts for both healthcare and dependent care;
•Health savings accounts and health reimbursement accounts, both of which receive a company contribution;
•Paid vacation and holidays;
•Parental leave;
•Short-term and long-term disability benefits;
•Wellness incentives for employees;
•Life and AD&D insurance benefits;
•Charitable donation matches; and
•Employee assistance program.
Employee Development: The Company recognizes that its culture and success is strengthened when employees are respected, motivated and engaged. The Company works to match employees with assignments that capitalize on the skills, talents and potential of each employee. The Company believes 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.
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Safety: Employee safety in the workplace is one of the Company’s core values. The Company is committed to strict compliance with applicable laws and regulations regarding workplace safety and provides on-going safety training, education and communication. Hazards in the workplace are actively identified and management tracks incidents so remedial actions can be taken to improve workplace safety. The Company believes communication related to “near misses,” safety incidents and protocols is essential to continuously developing and maintaining best-practices related to safety and enables identification and correction of operational practices that might impair employee safety or health.
Company Ethics: The Company has processes in place for compliance with its Code of Corporate Conduct, Insider Trading Policy and Anti-Corruption Policy. All of the Company's Directors and employees annually complete certifications with respect to compliance with the Company's Code of Corporate Conduct. In addition, all employees of the Company are required to complete annual Code of Corporate Conduct training. Ethics are deeply embedded in the Company’s values and business processes. The Company also maintains an ethics related hotline, managed by a third party, through which individuals can anonymously raise concerns or ask questions about business behavior.
Community Engagement: The Company supports its local communities and is committed to helping them remain safe, healthy and resilient. The Company's past activities include corporate donations, volunteerism and education. Community engagement is encouraged and supported through the Company's matching gift program. The Company will match employee contributions up to $5,000 per employee if program criteria are met.
Available Information
The Company makes its 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, free of charge, through its 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 the Company's 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 the Company's website is intended to be an inactive textual reference only.
Under Rule 12b-2 of the Exchange Act, the Company qualifies as a “smaller reporting company” because its public float as of the last business day of the Company’s most recently completed second quarter was less than $250 million. For as long as the Company remains a “smaller reporting company,” it 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.
Government Regulation
The Company's operations are subject to various federal, state and local laws and regulations on matters such as employee health and safety, and certain environmental laws and regulations relating to, among other matters, the reclamation and restoration of coal mining properties, air pollution, water pollution, the disposal of wastes and effects on groundwater. In addition, the electric power generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities that could affect demand for coal from the Company's Coal Mining segment. Many aspects of the production, pricing and marketing 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 the Company’s Minerals Management segment.
Numerous governmental permits and approvals are required for coal mining operations. The Company's subsidiaries hold or will hold the necessary permits at all of its coal mining operations except Demery and Caddo Creek, where the customers hold the respective permits. The Company believes, based upon present information provided to it by these third-party mine permit holders, that these third parties have all permits necessary for the Company to operate or reclaim Caddo Creek and Demery; however, the Company cannot be certain that these third parties will be able to maintain all such permits in the future.
At the coal mining operations where the Company's subsidiaries hold the permits, the Company is required to prepare and present to federal, state or local governmental authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment and public and employee health and safety.
Some laws, as discussed below, place many requirements on the coal mining operations and the limestone quarries where the Company provides services. Federal and state regulations require regular monitoring of the Company's operations to ensure compliance.
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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
The Company's 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. The Company has 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 Coal Mining segment.
Surface Mining Control and Reclamation Act
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; however, the cost of obtaining a permit is usually between $1,000,000 and $5,000,000, and the cost of obtaining a permit renewal is usually between $15,000 and $100,000.
The Abandoned Mine Land Fund, which is provided for by SMCRA, imposes a fee on certain coal mining operations. The proceeds are intended to be used principally to reclaim mine lands closed prior to 1977. In addition, the Abandoned Mine Land Fund also makes transfers annually to the United Mine Workers of America Combined Benefit Fund (the “Fund”), which provides health care benefits to retired coal miners who are beneficiaries of the Fund. The 2021 Infrastructure Investment and Jobs Act reauthorized the Abandoned Mine Land fee at a reduced rate. The fee for lignite coal was reduced from $0.08 per ton to $0.064 per ton and for other surface-mined coal from $0.28 per ton to $0.224 per ton. These fees have been reauthorized until the end of fiscal year 2035.
SMCRA establishes operational, reclamation and closure standards for surface coal mines. The Company accrues for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharges, at mines where the Company's subsidiaries hold the mining permit. These obligations are largely unfunded, with the exception of the final mine closure costs for the Coyote Creek Mine, which are being funded throughout the production stage.
SMCRA stipulates compliance with many other major environmental programs, including the CAA and CWA. The U.S. Army Corps of Engineers regulates activities affecting navigable waters, and the U.S. Bureau of Alcohol, Tobacco and Firearms regulates the use of explosives for blasting. In addition, the U.S. Environmental Protection Agency (the “EPA”), the U.S. Army Corps of Engineers and the OSMRE have engaged in a series of rulemakings and other administrative actions under the CWA and other statutes that are directed at reducing the impact of coal mining operations on water bodies.
The Company does not believe there is any significant risk to the Company's subsidiaries ability to maintain its existing mining permits or its ability to acquire future mining permits for its mines.
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Clean Air Act and Affordable Clean Energy Rule ("ACE")
The process of burning coal can cause many compounds and impurities in the coal to be released into the air, including sulfur dioxide, nitrogen oxides, mercury, particulates and other matter. The CAA and the corresponding state laws that extensively regulate the emissions of materials into the air affect coal mining operations both directly and indirectly. Direct impacts on coal mining operations occur through CAA permitting requirements and/or emission control requirements relating to air contaminants, especially particulate matter. Indirect impacts on coal mining operations occur through regulation of the air emissions of sulfur dioxide, nitrogen oxides, mercury, particulate matter and other compounds emitted by coal-fired power plants. The EPA has promulgated or proposed regulations that impose tighter emission restrictions in a number of areas, some of which are currently subject to litigation. The general effect of tighter restrictions is to reduce demand for coal. Ongoing reduction in coal’s share of the capacity for power generation could have a material adverse effect on the Company’s business, financial condition and results of operations.
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 national ambient air quality standards ("NAAQS") every time a NAAQS is issued or revised by the EPA. The EPA has adopted NAAQS for several pollutants, which continue to be reviewed periodically for revisions. When the EPA adopts new, more stringent NAAQS for a pollutant, some states have to change their existing SIPs. If a state fails to revise its SIP and obtain EPA approval, the EPA may adopt regulations to effect the revision. Coal mining operations and coal-fired power plants that emit particulate matter or other specified material are, therefore, affected by changes in the SIPs. Through this process over the last few years, the EPA has reduced the NAAQS for particulate matter, ozone, and nitrogen oxides. The Company's coal mining operations and power generation customers may be directly affected when the revisions to the SIPs are made and incorporate new NAAQS for sulfur dioxide, nitrogen oxides, ozone and particulate matter. In March 2019, the EPA published a final rule that retains the current primary (health-based) NAAQS for sulfur oxides (SOx) without revision. The current primary standard is set at a level of 75 parts per billion, as the 99th percentile of daily maximum 1-hour SO2 concentrations, averaged over 3 years. In mid-2011, the EPA finalized the Cross-State Air Pollution Rule ("CSAPR") to address interstate transport of pollutants. This affects states in the eastern half of the U.S. and Texas. This rule imposes additional emission restrictions on coal-fired power plants to attain ozone and fine particulate NAAQS. The EPA began implementation of the rule in 2015, when Phase I emission reductions in sulfur dioxide and nitrogen dioxide became effective. Phase II reductions became effective in 2017. In 2016, the EPA mandated additional reductions in nitrogen oxide emissions. The U.S. Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") remanded the CSAPR Update to the EPA to address the court’s holding that the rule unlawfully allows significant contribution to continue beyond downwind attainment deadlines. In 2018, the EPA finalized all remaining ozone designations to comply with the 2015 ozone air quality standards. The U.S. Court of Appeals for the D.C. Circuit issued a per curium opinion rejecting various industry challenges to the EPA’s 2015 revisions to the ozone NAAQS, including that the EPA was required to consider certain adverse effects and background ozone when setting the standards. None of the power plants supplied by the Company are within non-attainment areas for ozone. In March 2021, EPA finalized the “Revised Cross-State Air Pollution Rule” to address the remand of the CSAPR update. The final rule requires no further obligations in states where the Company’s customers operate a power plant.
The CAA Acid Rain Control Provisions were promulgated as part of the CAA Amendments of 1990 in Title IV of the CAA (“Acid Rain Program”). The Acid Rain Program required reductions of sulfur dioxide emissions from coal-fired power plants. The Acid Rain Program is now a mature program, and the Company believes that any market impacts of the required controls have likely been factored into the coal market.
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. This program may restrict the construction of new coal-fired power plants, the operation of which may impair visibility at and around the Class I Areas. Additionally, the program requires certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxide and particulate matter. States were required to submit Regional Haze SIPs to the EPA in 2007; however, many states did not meet that deadline. In 2016, the EPA finalized revisions to the Regional Haze Rule which addresses requirements for the second planning period. In September 2019, the EPA issued final regional haze guidance that indicates that a re-evaluation of sources already subject to best available retrofit technologies ("BART") is likely unnecessary. The guidance also encourages states to balance visibility benefits against other factors in selecting the measures necessary to make “reasonable progress” toward natural visibility conditions. Finally, when comparing various control options to determine which ones may be “cost-effective,” the final guidance recommends comparing cost to visibility benefits. In July of 2021, the EPA released a memorandum to clarify the guidance issued in 2019. While this clarification memorandum attempted to reverse some of the core conclusions made in the 2019 guidance, it was released after the air analyses to develop individual SIPs had been completed and just prior to the SIP submittal deadline to the EPA, which was July 31, 2021. Many SIP submittals were delayed due to emissions modeling and continue to be developed and scrutinized. SIPs will be sent to the EPA for approval following both review by federal land managers of the National Park Service, the United States Fish and
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Wildlife Service and the United States Forest Service and all corresponding public comment periods. See "Item 1A - “Risk Factors” on page 20 for further discussion of the regional haze program.
Under the CAA, new and modified sources of air pollution must meet certain new source standards (the “New Source Review Program”). In the late 1990s, the EPA filed lawsuits against owners of many coal-fired power plants in the eastern U.S. alleging that the owners performed non-routine maintenance, causing increased emissions that should have triggered the application of these new source standards. Some of these lawsuits have been settled with the owners agreeing to install additional emission control devices in their coal-fired power plants. The EPA has clarified the process for evaluating whether the New Source Review (“NSR”) permitting program would apply to proposed projects at existing air pollution sources. Under the NSR program, before constructing a new stationary emission source or a modification of an existing major source, the source owner or operator must determine whether the new source will emit or the modification will increase air emissions above certain thresholds. The rule makes it clear that both emissions increases and decreases from a major modification at an existing source are to be considered during Step 1 of the two-step NSR applicability test which is designed to determine if there is a “significant emission increase”. In October 2021, the EPA denied a petition for reconsideration and administrative stay of the final rule; however, the remaining litigation and the uncertainty around the NSR program rules could adversely impact demand for coal. Any additional new controls may have an adverse impact on the demand for coal, which may have a material adverse effect on the Company’s business, financial condition or results of operations.
Under the CAA, the EPA also adopts national emission standards for hazardous air pollutants. In December 2011, the EPA adopted a final rule called the Mercury and Air Toxics Standard (“MATS”), which applies to new and existing coal-fired and oil-fired units. This rule requires mercury emission reductions in fine particulates, which are being regulated as a surrogate for certain metals.
The Company's power generation customers must incur substantial costs to control emissions to meet all of the CAA requirements, including the requirements under MATS and the EPA's regional haze program. These costs raise the price of coal-generated electricity, making coal-fired power less competitive with other sources of electricity, thereby reducing demand for coal. If the Company's customers cannot offset the cost to control certain regulated pollutant emissions by lowering costs or if the Company's customers elect to close coal-fired units, the Company’s business, financial condition and results of operations could be materially adversely affected.
Global climate change continues to attract considerable attention in the United States. The U.S. Congress has considered climate change legislation aimed at reducing greenhouse gas (“GHG”) emissions, particularly from coal combustion by power plants. Enactment of laws and passage of regulations regarding GHG emissions by the U.S. or additional states, or other actions to limit carbon dioxide emissions, such as opposition by environmental groups to expansion or modification of coal-fired power plants, could result in electric generators switching from coal to other fuel sources.
The U.S. 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 resources, such as wind or solar power. Some states have established programs to reduce GHG emissions. Further, governmental agencies have been providing 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 EPA introduced a GHG regulation program under the CAA by issuing a finding that the emission of six GHGs, including carbon dioxide and methane, may reasonably be anticipated to endanger public health and welfare. Based on that finding, the EPA published a New Source Performance Standard for greenhouse gases, applicable to certain new power plants. In 2019, the EPA issued the Affordable Clean Energy ("ACE") Rule to reduce GHG emissions from existing electric generating units ("EGUs"). In contrast to the Clean Power Plan, the ACE rule limited "best system of emission reduction" ("BSER") to only "inside the fenceline" heat rate improvement technologies or systems that can be applied at an affected coal-fired EGU. The ACE rule was challenged by a suite of petitioners before the U.S. Circuit Court of Appeals, District of Columbia Circuit ("DC Circuit") which subsequently ruled that the EPA erred when it rescinded the Clean Power Plan and they vacated the ACE rule. In early 2021, the EPA issued an endangerment/significant contribution finding for carbon dioxide emissions from coal-fired power plants. In addition, the DC Circuit court ruling was challenged by several parties, including the Company, and the Supreme Court of the United States recently granted certiorari. The Supreme Court of the United States will hear the case in February 2022. Depending on the outcome of the Supreme Court ruling, the EPA may draft a new rule to regulate carbon dioxide emissions which, depending on the scope and applicability of the rule, may have a material adverse effect on the Company’s business, financial condition or results of operations.
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The U.S. has not implemented the 1992 Framework Convention on Global Climate Change (“Kyoto Protocol”), which became effective for many countries on February 16, 2005. The Kyoto Protocol was intended to limit or reduce emissions of GHGs. The U.S. has not ratified the emission targets of the Kyoto Protocol or any other GHG agreement. Though the U.S. has not accepted these international GHG limiting treaties, numerous lawsuits and regulatory actions have been undertaken by states and environmental groups to try to force controls on the emission of carbon dioxide; or to prevent the construction of new coal-fired power plants.
As a successor to the Kyoto Protocol, in 2015, international negotiators finalized the Paris Agreement under the United Nations Framework Convention on Climate Change (“Paris Agreement”). Unlike the Kyoto Protocol, the Paris Agreement has no binding GHG reduction mandates on signatories.Participating countries only submit a description of their intended GHG reductions, and provide periodic progress updates, with no penalties for not meeting their self-imposed targets.The Paris Agreement also includes language stating that developed countries will provide financial assistance to help developing countries meet their GHG targets and adapt to climate change, but there are no mandated contributions. In November 2020, the United States formally withdrew from the Paris Agreement; however, the United States rejoined in February 2021. The renegotiation and implementation of the Paris Agreement, or other international agreements, the regulations promulgated to date by the EPA with respect to GHG emissions or the adoption of new legislation or regulations to control GHG emissions, could have a materially adverse effect on the Company’s business, financial condition and results of operations.
Significant public opposition has also been raised with respect to the proposed construction of certain new coal-fired EGUs due to the potential for increased air emissions. Such opposition, as well as any corporate or investor policies against coal-fired EGUs or requiring disclosures related to global climate change, could also reduce the demand for the Company's coal or marketability of NACCO stock. Further, policies limiting available financing for the development of new coal-fueled EGUs or coal mines or the retrofitting of existing EGUs could adversely impact the global demand for coal in the future. The potential impact on the Company 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 force electricity generators to diminish their reliance on coal as a fuel source. In view of the significant uncertainty surrounding each of these factors, it is not possible for the Company to predict reasonably the impact that any such laws, regulations or other policies may have on the Company's business, financial condition and results of operations. However, such impacts could have a material adverse effect on the Company's business, financial condition and results of operations.
The Company believes it has obtained all necessary permits under the CAA at all of its coal mining operations where it is responsible for permitting and is in compliance with such permits.
Clean Water Act
The Clean Water Act ("CWA") affects coal mining operations by establishing in-stream water quality standards and treatment standards for waste water discharge. Permits requiring regular monitoring, reporting and performance standards govern the discharge of pollutants into water. Waters discharged from coal mines are required to meet these standards. These federal and state requirements could require more costly water treatment and could materially adversely affect the Company’s business, financial condition and results of operations.
The Company believes it has obtained all permits required under the CWA and corresponding state laws and is in compliance with such permits. In many instances, mining operations require securing CWA authorization or a permit from the U.S. Army Corps of Engineers for operations in waters of the United States. The U.S. Army Corps of Engineers and EPA jointly revised the definition of a water of the United States ("WOTUS") in the June 2020 Navigable Water Protection Rule ("NWPR"). The new definition was challenged in court and two court cases resulted in vacatur of the NWPR. In December 2021, the EPA and COE released a draft “Step One” rule to redefine WOTUS by formally rescinding the NWPR and replacing it with a new definition. If the new definition is promulgated as drafted, some of the Company's operations could incur additional costs to mitigate streams and wetlands.
Bellaire is treating mine water drainage from coal refuse piles associated with two former underground coal mines in Ohio and one former underground coal mine in 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. See Note 7 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's asset retirement obligations.
Bellaire was notified by the Pennsylvania Department of Environmental Protection ("DEP") during 2004 that in order to obtain renewal of a permit, Bellaire would be required to establish a mine water treatment trust (the "Trust"). See Note 7 and Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on the Trust.
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Resource Conservation and Recovery Act
The 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 December 2014, the EPA finalized a rule specifying management standards for coal combustion residuals or coal ash ("CCRs") as a non-hazardous waste. In 2018, the EPA finalized revisions to the 2014 regulations in response to litigation of the 2014 rule.One revision allows a state director (in a state with an approved CCR permit program) or the EPA (where EPA is the permitting authority) to suspend groundwater monitoring requirements if there is evidence that there is no potential for migration of hazardous constituents to the uppermost aquifer during the active life of the unit and post closure care. The second revision allows issuance of technical certifications in lieu of a professional engineer. In addition, the EPA revised the groundwater protection standards and extended the deadline for some facilities that must close CCR units. In 2020, the EPA finalized additional changes to the CCR rule that classified all clay-lined surface impoundments that receive CCR as unlined, which triggered a pond closure date of April 2021 for impoundments that failed the aquifer location restriction. The EPA also established alternative deadlines to cease receipt of waste to include new site-specific alternatives due to lack of capacity with a deadline to initiate closure no later than October 15, 2023 and a new site-specific alternative due to permanent cessation of coal-fired boilers with two deadlines to complete closure: (a) no later than October 17, 2023 for surface impoundments 40 acres or smaller; and (b) October 17, 2028 for surface impoundments larger than 40 acres. This new rule 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.
The EPA rule exempts CCRs beneficially used at mine sites and reserves any regulation thereof to the OSMRE. The OSMRE suspended all rulemaking actions on CCRs, but could re-initiate them in the future. The outcome of these rulemakings, and any subsequent actions by EPA and OSMRE, could impact those Company operations that beneficially use CCRs.If the Company were unable to beneficially use CCRs, its revenues for handling CCRs from its customers may decrease and its costs may increase due to the purchase of alternative materials for beneficial uses.
National Environmental Policy Act
NEPA requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement. There are certain actions associated with surface coal mining that may trigger these types of assessments by federal agencies. When a NEPA action is required, the Company provides the required information to the appropriate federal agency so that they may complete the environmental assessment. Historically, this process has been lengthy and may take several years to complete. In July 2020, the White House Council on Environmental Quality ("CEQ") issued a final rule updating the original NEPA regulations; however, it was immediately challenged by states and non-governmental organizations. In October 2021, the CEQ issued a new draft rule rescinding many of the revisions from 2020 update. If finalized as drafted, the revised NEPA regulations could adversely affect the Company’s ability to secure necessary permits.
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 and its individual members, 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 the Company any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.
Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. The Company cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the Minerals Management segment. Sales of crude oil, condensate and natural gas liquids ("NGLs") are not currently regulated and are made at market prices.
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Environmental Matters
Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into 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 the Company’s mineral interests, which could materially adversely affect the 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 a permit before drilling commences, restrict the types, quantities and concentrations 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 operations. The strict, joint and several liability nature of such laws and regulations could impose liability upon the operators on the Company’s 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. 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 Minerals Management segment.
Drilling and Production
The operations of the Company’s third-party lessees are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The states, and some counties and municipalities, in which the Company has 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 or "allowables";
•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 the Company’s 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 the Company’s 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 the Company’s mineral interests, negatively affect the economics of production from these wells or to 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 the Company's 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.
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.
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However, in recent years efforts have been made to regulate hydraulic fracturing at the federal level. In addition, the Biden administration has signaled the intent to stop hydraulic fracturing on federal land.
In addition, 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 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 the Company’s mineral interests 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 the Company’s 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 the Company’s mineral interests.
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 the Company’s 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 the Company holds 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 the Company holds minerals interests could cause lessees to incur increased costs arising from species protection
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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, the Company cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can the Company determine what effect, if any, future regulatory changes might have on natural gas-related activities.
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, the Company believes that the regulation of oil transportation rates will not affect its 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, the Company believes that access to oil pipeline transportation services generally will be available to its operators to the same extent as to the Company or its competitors.
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State Regulation
Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of oil production and a 7.5% severance tax on the market value of natural gas production. 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 the Company 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 drilled by third-party lessee's and to limit the number of wells or locations the Company's third-party lessee operators can drill.
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. The Company does not believe that compliance with these laws will have a material adverse effect on its results of operations or financial condition.
Comprehensive Environmental Response, Compensation and Liability Act
The Comprehensive Environmental Response, Compensation and Liability Act ("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. The Company must also comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.
From time to time, the Company has 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, the Company may incur material liabilities or costs related to environmental matters in the future, and such environmental liabilities or costs could materially and adversely affect the Company’s 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 the Company is required to conduct its operations.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
The following tables set forth as of March 1, 2022 the name, age, current position and principal occupation and employment during the past five years of the Company’s executive officers. There exists no arrangement or understanding between any executive officer and any other person pursuant to which such executive officer was selected.
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EXECUTIVE OFFICERS OF THE COMPANY
Name Age Current Position Other Positions
PRINCIPAL OFFICERS OF THE COMPANY’S SUBSIDIARIES
Name Age Current Position Other Positions
Philip N. Berry 54 President - NAMining (from prior to 2017)
Carroll L. Dewing 65 Vice President - Operations of NACoal (from January 2017)
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Item 1A. RISK FACTORS
The Company operates 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 the Company’s business, financial condition, operating results or cash flows. The following risk factors are not an exhaustive list of the risks associated with the Company’s business. New factors may emerge or changes to these risks could occur that could materially affect the Company’s business.
Risks related to the Coal Mining segment
Termination of or default under long-term mining contracts could adversely affect the Company's business, financial condition, results of operation and cash flows.
Substantially all of the Coal Mining segment's profits are derived from long-term mining contracts. Although the Company has long-term contracts, numerous 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, including as discussed in “Item 1. Business — Business Developments" on page 2 or a result of GRE’s failure to complete the sale of Coal Creek Station and the adjacent high-voltage direct current transmission line to Rainbow Energy and its affiliates currently anticipated to close in the second quarter of 2022, could have a material adverse effect on the Company’s business, financial condition and results of operations.
State implementation of the EPA’s Regional Haze Rule (“RHR”) could require Coyote Creek’s customers to incur significant new costs at the Coyote Station power plant, which could, dependent on determinations by state regulatory commissions regarding approval to recover such costs from the customers of Coyote Creek’s customer, negatively impact Coyote Creek’s customers’ net income, financial position and cash flows. The Company understands that the North Dakota Department of Environmental Quality (“NDDEQ”) could require sources subject to RHR Round 2 reasonable progress determinations, including Coyote Station, to undertake emissions control measures. The emissions modeling conducted for the combined western state agencies affected by the RHR was delayed and has subsequently delayed the NDDEQ state implementation plan process. Therefore, the NDDEQ's state implementation plan, which was due to the EPA by July 2021, is anticipated to be submitted to EPA early in 2022. If NDDEQ requires significant emissions controls at Coyote Station power plant by December 31, 2028, it may not be economically feasible for Coyote Creek's customers to invest in such equipment and an early retirement of Coyote Station and the Coyote Creek mine could be necessary.
The Company could be negatively impacted by the decisions of Coyote Creek's customers. In September 2021, one of Coyote Creek's customers, Otter Tail Power Company, filed its 2022 Integrated Resource Plan in Minnesota and North Dakota which included its intent to start the process of withdrawal from its 35 percent ownership interest in Coyote Station power plant with an anticipated exit from the plant by December 31, 2028.
Under certain circumstances of default or termination of Coyote Creek’s Lignite Sales Agreement (“LSA”), the Company would be obligated for payment of a "make-whole" amount to Coyote Creek’s third-party lenders. The “make-whole” amount is based on the excess, if any, of the discounted value of the remaining scheduled debt payments over the principal amount. In addition, in the event Coyote Creek’s LSA is terminated on or after January 1, 2024 by Coyote Creek’s customers, the Company is obligated to purchase Coyote Creek’s dragline and rolling stock for the then net book value of those assets. Any decision by Coyote Creek’s customers to reduce operations or prematurely close the Coyote Creek mine would have a material adverse effect on the Company’s results of operations, financial position and cash flows.
The loss of, or significant reduction in, purchases by NACCO's coal customers could adversely affect the Company's business, financial condition, results of operation and cash flows.
For the year ended December 31, 2021, the Coal Mining segment derived approximately 68% of earnings of unconsolidated operations from two customers, Basin Electric and GRE. There are inherent risks whenever a significant percentage of total earnings are concentrated with a limited number of customers. Earnings from the 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 the Company's control. If any of the Coal Mining segment's customers experience declining demand due to market, economic, regulatory or competitive conditions, it could have an adverse effect on the Company's 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 the Company is unable to renew expiring long-term sales agreements with existing customers or enter into new supply agreements, the Company's business, financial condition, results of operations and cash flows could be adversely affected. See “Item 1. Business — Business
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Developments" on page 2 in this Form 10-K for further discussion.
MLMC is subject to risks associated with its capital investment, operating and equipment costs, growing use of alternative generation that competes with coal fired generation, changes in customer demand and inflationary adjustments.
The profitability of MLMC is subject to the risk of loss of investment in this operation, increases in the cost of mining, changes in customer demand, growing competition from alternative power generation that competes with coal-fired generation and the emergence of adverse mining conditions. At MLMC, the costs of mining operations are not reimbursed by MLMC's customer. As such, increased costs at MLMC or decreased revenues could materially reduce the Company's profitability. Any reduction in customer demand at MLMC, including reductions related to reduced mechanical availability of the customer’s power plant, would adversely affect the Company's operating results and could result in significant impairments. MLMC has approximately $136 million of long-lived assets, including property, plant and equipment and a coal supply agreement intangible asset, which are subject to periodic impairment analysis and review. 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 operating costs and other factors that impact anticipated revenue and customer demand, requires significant judgment. Actual future operating results could differ significantly from these estimates, which may result in an impairment charge in a future period, which could have a substantial impact on the Company’s results of operations.
MLMC sells lignite at contractually agreed upon prices which are subject to changes in the level of established indices over time. 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 delivers coal to the Red Hills Power Plant in Ackerman, Mississippi. The Red Hills Power Plant supplies electricity to TVA under a long-term PPA. MLMC’s contract with its customer runs through 2032. TVA’s power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables. In 2019, TVA published its updated Integrated Resource Plan, which indicates plans to increase its reliance on solar power. A decrease in the number of days TVA dispatches the Red Hills Power Plant would reduce MLMC's customer's demand for coal. The decision of which power plants to dispatch is determined by TVA.
Choctaw Generation Limited Partnership ("CGLP") leases the Red Hills Power Plant from a Southern Company subsidiary pursuant to a leveraged lease arrangement. CGLP's ability to make required payments to the Southern Company subsidiary is dependent on the operational performance of the Red Hills Power Plant. During 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease which resulted in a full impairment of the lease investment. If any future lease payment is not paid in full, the Southern Company subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the Red Hills Power Plant. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the Red Hills Power Plant from the Southern Company subsidiary. A foreclosure of the Red Hills Power Plant could have a material adverse effect on MLMC's financial condition, results of operations and cash flows. Southern Company publicly disclosed that all required lease payments have been paid in full through December 31, 2021
Similar to the Company's unconsolidated mines, 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 its inventory carrying value using the lower of cost and net realizable value approach, which could adversely affect MLMC’s results of operations.
Changes in customer demand for any reason, including, but not limited to, reduced mechanical availability of the customer’s power plant, dispatch of power generated by other energy sources ahead of coal, fluctuations in demand due to unanticipated weather conditions, regulations or comparable policies which may promote planned and unplanned outages at the Red Hills Power Plant, economic conditions, including an economic slowdown and a corresponding decline in the use of electricity, 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
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Unconsolidated Subsidiaries' customers pay the Company its 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, fluctuations in demand due to unanticipated weather conditions, scheduled and unscheduled outages at the Coal Mining segment's customers' facilities, unplanned equipment failures, economic conditions or governmental regulations or comparable policies which may promote dispatch of power generated by renewables, such as wind or solar, and the realignment of customers' power generation portfolios that reduce the electric power generated from coal could have a material adverse effect on the Company's 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 the Company's profitability.
Changes in coal consumption patterns of U.S. electric power generators could adversely affect the Company's 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; environmental and other governmental regulations, including those impacting coal-fired power plants; and energy conservation efforts and related governmental policies.
Changes in the utility industry that affect NACCO's customers could also adversely affect the Company. 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 has the most potential to continue to displace a significant amount of coal-fired electric power generation in the near term. 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.
Changes in federal and state mandates that would include an acceleration in the use of electricity derived from renewable energy sources could result in a decrease in coal consumption by the electric power generation industry and the Company’s customers.
Certain of the Coal Mining segment’s customers, including MLMC's customer, benefit or have benefited from a tax credit under Section 45 of the Internal Revenue Code. The benefit results in a reduction to the cost of coal-fired electric power generation. The elimination or expiration of the Section 45 tax credit would increase the cost of the coal-fired electric power generation from these facilities and could result in the power these facilities produce being less economical than other sources of power generation, which could reduce demand and result in a decrease in coal consumption.
Any of these risks could result in a decrease in coal consumption by the Company’s customers and could have a material adverse effect on the Company’s business, financial condition and results of operations.
Government regulations could impose costly requirements on the Company and its customers.
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. The Company is 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 the Company's mining operations or its cost structure, or its customers. All of these factors could significantly reduce the Company's profitability. See “Item 1. Business — Government Regulation" on page 9 in this Form 10-K for further discussion.
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The Company is subject to burdensome federal and state mining regulations and the assumptions underlying the Company's reclamation and mine closure obligations could be materially inaccurate.
Federal and state statutes require the Company to restore mine property in accordance with specified standards and an approved reclamation plan, and require that the Company obtain and periodically renew permits for mining operations. Regulations require the Company to incur the cost of reclaiming current mine disturbance at operations where the Company holds the mining permit. Estimates of the Company's total reclamation and mine closing liabilities are based upon permit requirements and the Company's 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 the Company’s business and could significantly reduce its profitability.
The Clean Air Act ("CAA") could reduce the demand for coal.
The process of burning coal can cause many compounds and impurities in the coal to be released into the air, including carbon dioxide, sulfur dioxide, nitrogen oxides, mercury, particulates and other matter. The CAA and the corresponding state laws that extensively regulate the emissions of materials into the air affect coal mining operations both directly and indirectly. Direct impacts on coal mining operations occur through CAA permitting requirements and/or emission control requirements relating to air contaminants, especially particulate matter. Indirect impacts on coal mining operations occur through regulation of the air emissions of carbon dioxide, sulfur dioxide, nitrogen oxides, mercury, particulate matter and other compounds emitted by coal-fired power plants. The EPA has discussed issuing or issued regulations that impose tighter emission restrictions on a number of these compounds, some of which are currently subject to litigation. The general effect of tighter restrictions is to reduce demand for coal. A reduction in coal’s share of the capacity for power generation could have a material adverse effect on the Company’s business, financial condition and results of operations. See “Item 1. Business — Government Regulation" on page 9 in this Form 10-K for further discussion.
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 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.
Mining operations are vulnerable to weather and other conditions that are beyond the Company's control.
Many conditions beyond the Company's control can decrease the delivery, and therefore the use, of coal to the Company's customers. These conditions include weather, pandemics, adverse mining conditions, unexpected maintenance problems and shortages of replacement parts, any of which could significantly reduce the Company's profitability.
The Company faces 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 the Company's mining operations in "Item 2 - Properties on page 31" has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K, which first became applicable to us for the fiscal year ended December 31, 2021. 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 in the Company's operational mines and other mining properties are based on many factors, including engineering, economic and geological data assembled and analyzed by internal staff and third parties, 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 from the Company's mining properties and new mining or other data received.
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There are numerous uncertainties inherent in estimating quantities and qualities of minerals and costs to mine recoverable reserves and resources, including many factors beyond the Company's control. Estimates of mineral reserves and resources necessarily 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 the Company's 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 the Company's minerals;
•Contractual arrangements, operating costs and capital expenditures;
•Development and reclamation costs;
•Mining technology and processing improvements;
•The effects of regulation by governmental agencies;
•The ability to obtain, maintain and renew all required permits;
•Employee health and safety; and
•NACCO's ability to convert all or any part of mineral resources to economically extractable mineral reserves.
As a result, actual tonnage recovered from identified mining properties and estimated revenues, expenditures and cash flows with respect to reserves and resources may vary materially from estimates. Thus, these estimates may not accurately reflect the Company’s actual reserves and resources. Any material inaccuracy in estimates related to the Company's 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 the Company 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 the Company's ability to mine coal reserves or result in significant unanticipated costs.
The Company conducts a significant part of its 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. The Company may not verify title to leased properties or associated coal reserves until the Company has committed to developing those properties or coal reserves. The Company may not commit to develop property or coal reserves until the Company has obtained necessary permits and completed exploration. As such, the title to property that the Company intends 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, the Company may incur unanticipated costs. In addition, some leases require the Company to produce a minimum quantity of coal and/or pay minimum production royalties. The Company's inability to satisfy those requirements may cause the leasehold interest to terminate.
Risks related to the NAMining segment
The Company has experienced growth in its NAMining business in recent periods and it may not be able to sustain growth or manage future growth effectively.
The Company has expanded its overall NAMining business, operations and headcount in recent periods. NAMining’s operating expenses may continue to increase as the Company scales the NAMining business, including growth outside of Florida, and provides general and administrative resources to support NAMining’s growth. As NACCO continues to grow the NAMining business, the Company must effectively integrate, develop and motivate new employees, as well as existing employees who are promoted or moved into new roles, while maintaining the effectiveness of its business execution. In part, NAMining’s success depends on its ability to integrate new customers in an efficient and effective manner. The Company anticipates that it 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 the Company is unable to manage this growth and the associated expenses effectively, the Company may not be able to take advantage of market opportunities or remain competitive. The Company may also fail to execute on its business plan or respond to competitive pressures, any of which could adversely affect the NAMining business, operating results and financial condition.
NAMining faces competition from aggregates producers that choose to self-perform mining operations and from other mining companies.
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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 its 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.
The Company is subject to risks involved in the development of new mining projects.
From time to time, the Company seeks 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, 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 the Company’s business, financial condition and results of operations.
NAMining 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, 2021, over 80% of the quarries NAMining operates 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 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 business.
Risks related to the Minerals Management segment
The Company has no control over the timing of the development and operation of its natural gas, oil and coal reserves extracted by third parties.
The Company owns mineral and royalty interests in the continental United States. The Company does not develop oil and gas reserves and is not a natural gas and oil producer. The Company derives income from royalty-based leases under which lessees make payments to the Company based on their sale of natural gas, oil and coal. As discussed in “Item 1. Business — Business Developments" on page 2, the Company acquired additional mineral and royalty interests during 2021 and 2020 and plans to continue to pursue acquisitions of additional mineral and royalty interests. Future royalty-based income is dependent on the number of oil and gas wells being developed and operated on the Company’s mineral acreage. The decision to pursue development and operation of oil and gas wells is made by third-party operators, not by the Company, and depends on a number of factors outside of the Company's control, including fluctuations in commodity prices (primarily natural gas), regulatory risk, the Company's 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 the Company owns mineral and royalty interests, the Company’s 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 its royalty payments or continue operations. A failure on the part of the lessee to make royalty payments gives the Company the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If the Company repossessed any of its properties, it would seek a replacement lessee. However, the Company may not be able to find a replacement lessee and, if it did, the Company might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, if the Company is 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 the Company’s expected royalty income and the Company’s profitability.
Minerals are a depleting asset. Unless the Company replaces existing mineral and royalty interests with new mineral and royalty interests and third-party lessees develop those mineral and royalty interests, the Company’s 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 the Company’s third-party lessees conduct successful ongoing well development activities or the Company continually acquires mineral and royalty interests, production and income related to the Company’s mineral and royalty interests will decline as those reserves are depleted. The future cash flow and results of operations of the Minerals Management segment are highly dependent on third-party operators’ success in developing the
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Company’s current and future mineral and royalty interests. These operators may not have access to the capital needed to develop the Company's mineral interests. The Company 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 the Company uses 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 the Company’s expected royalty income and the Company’s profitability.
Substantially all of the Minerals Management 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 the Company’s interests are sold. Prices of oil and natural gas are volatile due to factors beyond the Company’s control. A substantial or extended decline in commodity prices may adversely affect the Minerals Management segment’s financial condition or results of operations.
The Minerals Management 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, market uncertainty and a variety of additional factors that are beyond the Company's 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 U.S. military operations in the Middle East and 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; and overall domestic and global economic conditions. A substantial or extended decline in commodity prices may adversely affect the Minerals Management segment’s financial condition or results of operations.
Risks related to corporate structure
The Company’s stock repurchase program could affect the price of NACCO’s common stock and increase volatility and may not enhance long-term shareholder value.
The Company’s 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 the Company's management based on a number of factors, including the availability of capital, other capital allocation alternatives, market conditions for the Company's Class A common stock and other legal and contractual restrictions. The stock repurchase program does not require the Company 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 the Company's Class A common stock. The existence of a stock repurchase program could cause the price of the Company's 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 the Company’s Class A common stock. There can be no assurance that any stock repurchases will enhance shareholder value because the market price of the Company’s Class A common stock may decline below the levels at which the Company 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 the Company to repurchase any dollar amount or number of shares of the Company's 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 the Company's Class A common stock to decline.
The price of NACCO's securities may be volatile.
The price of the Company's 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 the Company's 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 or acts of terrorism;
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(v) announcements concerning NACCO, its customers or its competitors; (vi) lack of trading liquidity as a result of low trading volumes could make it difficult for investors to sell shares; and (vii) 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 the Company's common stock, regardless of NACCO's actual operating performance. As a result of all of these factors, investors in the Company's common stock may not be able to resell their stock at or above the price they paid or at all. Further, NACCO 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 the Company's operating results.
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 NACCO's 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.
NACCO's certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.
Provisions contained in the Company's certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire the Company, even if doing so might be beneficial to NACCO's stockholders. Provisions of the Company's 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 NACCO's common stock and may have the effect of delaying or preventing a change in control.
NACCO is a smaller reporting company and cannot be certain if the reduced disclosure requirements applicable to smaller reporting companies will make the Company's common stock less attractive to investors.
The Company is 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 the Company's performance with other public companies.
NACCO cannot predict whether investors will find the Company's 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 the Company's common stock and the stock price may be more volatile.
Certain members of the Company's extended founding family own a substantial amount of its 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.
The Company has 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, 2021, accounted for approximately 26 percent of the voting power of the Company. Holders of Class B common stock are entitled to cast ten votes per share and, as of December 31, 2021, accounted for the remaining voting power of the Company. As of December 31, 2021, certain members of the Company's extended founding family held approximately 34 percent of the Company's outstanding Class A common stock and approximately 98 percent of the Company's outstanding Class B common stock. On the basis of this common stock ownership, certain members of the Company's extended founding family could have exercised approximately 81 percent of the Company's 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 the Company's certificate of incorporation and sales of the Company or substantially all of its assets. Because certain members of the Company's extended founding family could prevent other stockholders from exercising significant influence over significant corporate actions, the Company may be a less attractive takeover target, which could adversely affect the market price of its common stock.
General Risk Factors
The Company’s effective income tax rate could be volatile and materially change as a result of changes in tax laws, mix of earnings and other factors.
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The Company is 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 the Company’s 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 the Company’s 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 the Company’s ability to maintain financing at current levels.
The Company may be unable to obtain financing on reasonable terms. Historically, the Company has addressed its 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. The Company’s wholly-owned subsidiary, NACoal, has a revolving line of credit of up to $150.0 million that expires in November 2025 (the "NACoal Facility"). The Company’s 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 combined with recent bankruptcies 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 obtaining a refinancing with terms that are not as favorable as the existing terms of such indebtedness, could have a material adverse effect on the Company's 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 the Company 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 benefits costs, leases and other obligations. Future federal and state laws and regulations 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 the Company is required by state and federal law to have bonds or other acceptable security in place before mining can commence or continue, 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 the Company's financing arrangements. In addition, as a result of increasing credit pressures on the coal industry, it is possible that surety bond providers could demand cash collateral as a condition to providing or maintaining surety bonds. Any such demands, could have a material adverse impact on the Company’s liquidity and financial position. If the Company is 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 the Company’s costs and likely require greater use of alternative sources of funding for this purpose, which would reduce the Company’s 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 the Company’s ability to maintain insurance coverage at current levels.
The Company holds a number of insurance policies, including director and officers’ liability and property and casualty insurance coverages. Because the Company is involved in coal mining, costs of insurance may increase substantially or insurance carriers may limit or decide not to insure the Company in the future. In addition, if the Company makes significant insurance claims under the Company’s insurance policies, such claims may have a material adverse effect on its 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 its liability insurance coverage limits, could have a material adverse effect on the Company's operating results and financial condition.
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Increasing emphasis and changing expectations with respect to environmental, social and governance matters may impose additional costs on the Company or expose the Company to new or additional risks.