UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
(Mark One)
 
 
þ
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the fiscal year ended December 31, 2019
or
¨
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 1-9172
NACCO INDUSTRIES, INC.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
 
34-1505819
(I.R.S. Employer Identification No.)
 
 
 
5875 Landerbrook Drive, Suite 220, Cleveland, Ohio
(Address of principal executive offices)
 
44124-4069
(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 ¨    NO þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
     YES ¨    NO þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
     YES þ     NO £
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
     YES þ     NO £

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

Smaller reporting company þ 
 
Emerging growth company¨

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)
     YES ¨    NO þ
Aggregate market value of Class A Common Stock and Class B Common Stock held by non-affiliates as of June 30, 2019 (the last business day of the registrant's most recently completed second fiscal quarter): $221,449,254
Number of shares of Class A Common Stock outstanding at February 21, 2020: 5,397,458
Number of shares of Class B Common Stock outstanding at February 21, 2020: 1,568,670
DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company's Proxy Statement for its 2020 annual meeting of stockholders are incorporated herein by reference in Part III of this Form 10-K.
 
 
 
 
 



NACCO INDUSTRIES, INC.
TABLE OF CONTENTS
 
 
 
PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
F-1
 

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PART I
Item 1. BUSINESS
General
NACCO Industries, Inc.® (“NACCO” or the “parent company”) is the public holding company for The North American Coal Corporation® ("NACoal").  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. The Company and its wholly-owned subsidiaries (collectively, "NACCO Industries, Inc. and Subsidiaries" or the "Company") operate in the mining and natural resources industries through three operating segments: Coal Mining, North American Mining ("NAMining") and Minerals Management.

The Coal Mining segment operates surface coal mines under long-term contracts with power generation companies and activated carbon producers pursuant to a service-based business model. The NAMining segment provides value-added contract mining and other services for producers of aggregates, lithium and other minerals. The Minerals Management segment promotes the development of the Company’s oil, gas and coal reserves, generating income primarily from royalty-based lease payments from third parties.

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

Included within other income is the financial results of NoDak Energy Services, LLC ("NoDak"). NoDak operates and maintains a coal drying system at a customer’s power plant. The NoDak contract expired in the first quarter of 2020.

The following map shows our current operations:
BW2020CONSOLIDATEDMAPA01.JPG


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Business Developments
In 2019, NAMining, through a new subsidiary, Sawtooth Mining, entered into a mining agreement to serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada. The Thacker Pass Project is 100% owned by Lithium Nevada Corp. Lithium Nevada plans to develop a lithium production facility near what is believed to be the largest known lithium deposit in the United States. Sawtooth Mining will provide comprehensive mining services similar to the Company's typical scope of work in the Coal Mining segment. The mining agreement provides that Lithium Nevada will reimburse Sawtooth Mining for its operating and mine reclamation costs, and pay Sawtooth Mining a management fee per metric ton of lithium delivered during the 20-year contract term. Lithium Nevada is in the process of securing permits and currently expects to commence construction in 2021 and production of lithium products in 2023.

During the development of the project, Sawtooth Mining will provide Lithium Nevada $3.5 million in cash, of which $1.5 million has been provided as of December 31, 2019, to assist in project development. Sawtooth Mining will also provide certain engineering services related primarily to mine design and permitting. Under the terms of the mining agreement, Lithium Nevada will pay Sawtooth Mining a success fee upon achievement of certain engineering, construction and production milestones. After Lithium Nevada secures required permits and financing for the project, Sawtooth Mining intends to acquire up to $50 million of mining equipment. The cost of this mining equipment will be reimbursed to Sawtooth Mining by Lithium Nevada over a six-year period from the equipment acquisition date.

NAMining serves as a platform for pursuing non-coal mining projects by leveraging the Company's core mining capabilities. In addition to the Thacker Pass Project, NAMining has grown from serving two customers at seven quarries utilizing 10 draglines in 2015 to serving 10 customers at 20 quarries utilizing 31 draglines and a rope shovel during 2019.

On September 29, 2017, the Company spun-off Hamilton Beach Brands Holding Company ("HBBHC"), a former wholly owned subsidiary. As a result of the spin-off, NACCO stockholders received one share of HBBHC Class A common stock and one share of HBBHC Class B common stock for each share of NACCO Class A or Class B common stock owned on the record date for the spin-off. 

On June 28, 2017, Southern Company and its subsidiary, Mississippi Power, suspended operations involving the coal gasifier portion of the Kemper County energy facility. Liberty Fuels Company, LLC ("Liberty") was the sole supplier of coal to fuel the gasifier under its contract with Mississippi Power. Liberty ceased all mining and delivery of lignite in 2017. The terms of the contract specified that Mississippi Power was responsible for all mine closure costs and Liberty receives compensation for providing mine reclamation services. As of December 31, 2019, the mine areas have been reclaimed and final mine reclamation activities, primarily monitoring, will continue until final bond release.

Bisti Fuels LLC (“Bisti”) became the contract miner at Navajo Transitional Energy Company's ("NTEC's") existing Navajo Mine on January 1, 2017. Under the 15 year Contract Mining Agreement, the Company is reimbursed for actual costs incurred and is paid a management fee per MMBtu delivered.
Segments
Operating segments are defined as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker to decide how to allocate resources and to assess performance. In the first quarter of 2019, the Company changed its reportable segments to reflect changes in the business, including growth at NAMining and Minerals Management. As of January 1, 2019, the Company’s operating segments are: (i) Coal Mining, (ii) NAMining and (iii) Minerals Management. While the Company continues to pursue opportunities to add new coal mining operations to the Coal Mining segment, the NAMining segment will serve as the platform for pursuing non-coal mining projects and the Minerals Management segment will work to capitalize on the Company’s oil, gas and coal reserves.
Additional information relating to financial and operating data on a segment basis (including unallocated items) is set forth under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in Part II of this Form 10-K and in Note 15 to the Consolidated Financial Statements contained in this Form 10-K.

Coal Mining Segment
The Coal Mining segment operates surface coal mines under long-term contracts with power generation companies and activated carbon producers pursuant to a service-based business model. Coal is surface-mined in North Dakota, Texas, Mississippi, Louisiana and on the Navajo Nation in New Mexico. Each mine is fully integrated with its customer operations.

The operating coal mines are: Bisti, Caddo Creek Resources Company, LLC (“Caddo Creek”), Camino Real Fuels, LLC (“Camino Real”), The Coteau Properties Company (“Coteau”), Coyote Creek Mining Company, LLC (“Coyote Creek”), Demery Resources Company, LLC (“Demery”), The Falkirk Mining Company (“Falkirk”), Mississippi Lignite Mining Company (“MLMC”) and The Sabine Mining Company (“Sabine”). Liberty is also included in the Coal Mining segment.

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Coteau, Coyote, Falkirk, MLMC and Sabine supply lignite coal for power generation. Bisti and Camino Real supply sub-bituminous and bituminous coal, respectively, for power generation. Caddo Creek and Demery supply lignite coal for the production of activated carbon. Each of these mines deliver their coal production to adjacent or nearby power plants, synfuels plants or activated carbon processing facilities under long-term supply contracts. With the exception of Camino Real, each mine is the exclusive supplier of coal to its customers' facilities. Camino Real’s customer takes all coal produced by the mine but also purchases additional coal from other suppliers.

This segment has a strong history of customer retention due to the long-term nature of its contracts and the proximity of the Company’s mines to its customers’ facilities. With the exception of Camino Real, whose contract expires in 2021 but has renewal provisions, other contract expiration dates range from 2022 through 2045. The contract that expires in 2022 may be extended for three additional periods of five years each, or until 2037, at the Company’s option.

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 exposure to spot coal market price fluctuations while providing steady 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 VIE's 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. The contracts for certain of the Company's Unconsolidated Subsidiaries permit or obligate the customer under some conditions to acquire the assets or stock of the subsidiary for an amount roughly equal to book value.

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, 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, the persistence of low diesel fuel prices can negatively affect 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.

Centennial Natural Resources (“Centennial”), located in Alabama, ceased coal production at the end of 2015. Since 2015, the Company has sold or transferred certain Centennial equipment and mineral reserves. The Company continues to evaluate strategies for the remaining mineral reserves and a dragline, which have no remaining book value. Cash expenditures related to mine reclamation at Centennial will continue until mine reclamation is complete, or ownership of, or responsibility for, the remaining mines is transferred. Centennial is a consolidated entity within the Coal Mining segment as the Company is responsible for carrying costs and final mine reclamation.

The coal reserves at Coteau, Falkirk, Coyote, MLMC and Centennial are owned or controlled by the Company. The coal reserves at all other mines are owned or controlled by the respective mine’s customer. Total coal reserves approximate 2.0 billion tons (including the unconsolidated coal mining subsidiaries), with approximately 1.1 billion tons committed to customers pursuant to long-term contracts.


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

The contracts under which certain of the Unconsolidated Subsidiaries operate provide that, under certain conditions, including default, the customer(s) involved may elect or be obligated to acquire the assets (subject to the liabilities) or the capital stock of the Coal Mining subsidiary for an amount effectively equal to book value. The Company does not know of any conditions of default that currently exist.

North American Mining 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 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 operates primarily at limestone quarries in Florida, but is focused on expanding outside of Florida and into mining materials other than limestone. During 2019, the Company entered into a mining agreement to serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada. NAMining utilizes both fixed price and management fee contract structures.

Minerals Management Segment
The Minerals Management segment promotes the development of the Company’s oil, gas and coal reserves, generating income primarily from royalty-based lease payments from third parties. The Company’s gas, oil and undeveloped coal reserves are located in Ohio (Utica and Marcellus shale natural gas), Louisiana (Haynesville shale and Cotton Valley formation natural gas), Mississippi (coal), Pennsylvania (coal, coalbed methane and Marcellus shale natural gas), Alabama (coal and coalbed methane and natural gas) and North Dakota (coal).

The majority of the Company’s existing reserves were acquired as part of its historical coal mining operations. The Minerals Management segment derives income primarily by entering into contracts with third-party operators, granting them the rights to explore, produce and sell natural resources in exchange for royalty payments based on the lessees' sales of natural gas and, to a lesser extent, oil and coal. Specialized employees in the Minerals Management segment also provide surface and mineral acquisition and lease maintenance services related to Company operations.

Customers
The principal customers of the Coal Mining segment are electric utilities, an independent power provider and producers of activated carbon.

The principal customers of the NAMining segment are limestone 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 coal producers.

In 2019, two customers and an oil and gas lessee individually accounted for more than 10% of consolidated revenue. In 2018 and 2017, two customers individually accounted for more than 10% of consolidated revenue. The following represents the revenue attributable to each of these entities as a percentage of consolidated revenue for those years:
 
 
 
Percentage of Consolidated Revenue
Customer
Segment
 
2019
 
2018
 
2017
Choctaw Generation Limited Partnership, LLLP
Coal Mining
 
48
%
 
60
%
 
60
%
CEMEX
NAMining
 
21
%
 
20
%
 
18
%
Ascent Resources
Minerals Management
 
12
%
 
n/a

 
n/a


The loss of either of these customers or the lessee 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.


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In addition to the customers listed above, the Company has certain subsidiaries that meet the definition of a VIE. 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. For the year ended December 31, 2019, the Coal Mining segment derived approximately 60% of the Earnings of Unconsolidated Operations from two customers, Basin Electric Power Cooperative and Great River Energy. 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 results of operations.

Competition
The Company has a strong history of customer retention due to the long-term nature of its contracts and the proximity of the Company’s coal mines to its customers’ facilities. The 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 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. Sustained low natural gas prices have resulted in an increase in electricity generated from natural gas leading to a decline in the use of coal-fired capacity in the United States. 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.  As an example, the Company estimates wind capacity in North Dakota has increased over 60% since 2015 to approximately 3,600 megawatts and wind developers have expressed an interest in building more than 7,000 megawatts of additional wind generation in North Dakota over the next several years. 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 power plants the Coal Mining segment supplies are generally younger and more efficient, with better environmental controls than most plants that have closed in recent years. The Coal Mining segment's customers continue to invest in efficiency and environmental upgrades to their facilities. Because the Coal Mining segment's customers’ power plants are competitive suppliers of electricity in their respective dispatch areas, the Company considers its surface coal mining operations to be well positioned relative to most other mines servicing coal-fired generating units.

Based on industry information, the Company believes it was one of the ten largest coal producers in the U.S. in 2019 based on total coal tons produced.

NAMining faces competition, primarily from aggregates producers which choose to self-perform mining operations.

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 and seasonal weather conditions, both of which can result in variations in limestone demand. The Minerals Management segment derives income from royalty-based leases under which lessees make payments to the Company based on their sale of natural gas and, to a lesser extent, oil and coal, extracted primarily by third parties. 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. 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 natural gas), fluctuations in production rates associated with operator decisions, regulatory risks, the Company's

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lessees' willingness and ability to incur well-development and other operating costs, and changes in the availability and continuing development of infrastructure.

Employees
As of December 31, 2019, the Company and its subsidiaries had approximately 2,400 employees, including approximately 2,000 employees at the Company’s unconsolidated mining operations of which 282 are represented by a union at Bisti. NACCO believes its current labor relations with both union and non-union employees are satisfactory.

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 inactive textual references 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.



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The location, mine type, reserve data, coal quality characteristics, sales tonnage and contract expiration date for the Coal Mining segment were as follows:

COAL MINING OPERATIONS ON AN “AS RECEIVED” BASIS
 
 
2019
 
2018
 
 
 
 
 
Proven and Probable Reserves (a)(b)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Committed
Under
Contract
 
Uncommitted
 
Total
 
Tons
Delivered
(Millions)
 
Owned
Reserves
(%)
 
Leased
Reserves
(%)
 
Total
Committed
and
Uncommitted
(Millions of
Tons)
 
Tons
Delivered
(Millions)
 
Contract
Expires
Mine/Reserve
Type of Mine
(Millions of Tons)
 
 
 
 
 
 
Unconsolidated Mines
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Freedom Mine (c)-
The Coteau Properties Company
Surface Lignite
432.8

 

 
432.8

 
13.5

 
3
%
 
97
%
 
444.5

 
14.2

 
2022
(d)
Falkirk Mine (c)-
The Falkirk Mining Company
Surface Lignite
375.7

 

 
375.7

 
7.4

 
1
%
 
99
%
 
373.6

 
8.4

 
2045
 
South Hallsville No. 1 Mine (c)(e)-
The Sabine Mining Company
Surface Lignite
63.1

 
39.5

 
102.6

 
2.6

 
(e)

 
(e)

 
(e)

 
3.8

 
2035
 
Five Forks Mine (c)(e)-
Demery Resources Company, LLC
Surface Lignite
4.9

 

 
4.9

 
0.1

 
(e)

 
(e)

 
(e)

 
0.2

 
2030
 
Marshall Mine (c)(e)-
Caddo Creek Resources Company, LLC
Surface Lignite
5.8

 
13.4

 
19.2

 
0.2

 
(e)

 
(e)

 
(e)

 
0.2

 
2044
 
Eagle Pass Mine (c)(e)-
Camino Real Fuels, LLC
Surface
Bituminous
3.8

 
11.8

 
15.6

 
1.5

 
(e)

 
(e)

 
(e)

 
2.1

 
2021
 
Coyote Creek Mine (c)-
Coyote Creek Mining Company, LLC
Surface Lignite
69.6

 

 
69.6

 
1.7

 
0
%
 
100
%
 
72.2

 
2.5

 
2040
 
Navajo Mine (c)(f)- Bisti Fuels Company
Surface
Sub-bituminous
(f)

 
(f)

 
(f)

 
5.0

 
(f)

 
(f)

 
(f)

 
4.1

 
2031
 
Consolidated Mines
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Red Hills Mine-
Mississippi Lignite Mining Company
Surface Lignite
106.0

 
134.0

 
240.0

 
2.6

 
44
%
 
56
%
 
231.3

 
3.0

 
2032
 
Centennial Natural Resources
Surface Bituminous

 
43.0

 
43.0

 

 
40
%
 
60
%
 
50.0

 

 
(g)
 
Total Developed
 
1,061.7

 
241.7

 
1,303.4

 
34.6

 
 
 
 
 
1,171.6

 
38.5

 
 
 
Undeveloped Mines
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
.
 
 
 
North Dakota
 

 
243.9

 
243.9

 

 
 
 
100
%
 
243.7

 

 
 
 
Texas
 

 
222.5

 
222.5

 

 
 
 
100
%
 
222.5

 

 
 
 
Eastern (h)
 

 
41.0

 
41.0

 

 
 
 
100
%
 
41.0

 

 
 
 
Mississippi
 

 
188.2

 
188.2

 

 
 
 
100
%
 
187.8

 

 
 
 
Total Undeveloped
 

 
695.6

 
695.6

 

 
 
 
 
 
695.0

 

 
 
 
Total Developed/Undeveloped
 
1,061.7

 
937.3

 
1,999.0

 
 
 
 
 
 
 
1,866.6

 
 
 
 
 


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Average Coal Quality (As received)
Mine/Reserve
 
Type of Mine
 
Coal Formation or
Coal Seam(s)
 
Average Seam
Thickness (feet)
 
Average
Depth (feet)
 
BTUs/lb
 
Sulfur
(%)
 
Ash
 (%)
 
Moisture (%)
Unconsolidated Mines
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Freedom Mine (c)-
The Coteau Properties Company
 
Surface Lignite
 
Beulah-Zap Seam
 
18

 
130

 
6,700

 
0.90
%
 
9
%
 
36
%
Falkirk Mine (c)-
The Falkirk Mining Company
 
Surface Lignite
 
Hagel A&B, Tavis
Creek Seams
 
8

 
90

 
6,200

 
0.62
%
 
11
%
 
38
%
South Hallsville No. 1 Mine (c)(e)-
The Sabine Mining Company
 
Surface Lignite
 
Wilcox Formation
 
2.7

 
94

 
6,453

 
1.29
%
 
16.6
%
 
33
%
Five Forks Mine (c)(e)-
Demery Resources Company, LLC
 
Surface Lignite
 
Wilcox Formation I Seam
 
4.5

 
45

 
6,940

 
0.44
%
 
8.8
%
 
37
%
Marshall Mine (c)(e)-
Caddo Creek Resources Company, LLC
 
Surface Lignite
 
Wilcox Formation A Seam
 
3.1

 
62

 
7,152

 
0.54
%
 
9.17
%
 
34
%
Eagle Pass Mine (c)(e)-
Camino Real Fuels, LLC
 
Surface Bituminous
 
Olmos Formation
 
5.5

 
50

 
6,700

 
1.00
%
 
40
%
 
11
%
Coyote Creek Mine (c)-
Coyote Creek Mining Company, LLC
 
Surface Lignite
 
Beulah-Zap Seam
 
10

 
95

 
6,900

 
0.98
%
 
8
%
 
36
%
Navajo Mine (c)(f)- Bisti Fuels Company
 
Surface
Sub-bituminous
 
(f)
 
(f)

 
(f)

 
(f)

 
(f)

 
(f)

 
(f)

Consolidated Mines
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Red Hills Mine-
Mississippi Lignite Mining Company
 
Surface Lignite
 
C, D, E, F, G, H Seams
 
3.6

 
150

 
5,200

 
0.60
%
 
14
%
 
43
%
Centennial Natural Resources
 
Surface Bituminous
 
Black Creek, New Castle, Mary Lee, Jefferson, American, Nickel Plate, Pratt Seams
 
1.75

 
178

 
13,226

 
2.00
%
 
10
%
 
4
%
Undeveloped Mines
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota
 

 
Fort Union Formation
 
13

 
130

 
6,500

 
0.8
%
 
8
%
 
38
%
Texas
 

 
Wilcox Formation
 
5

 
120

 
6,800

 
1.0
%
 
16
%
 
30
%
Eastern
 

 
Freeport & Kittanning Seams
 
4

 
400

 
12,070

 
3.3
%
 
12
%
 
3
%
Mississippi
 

 
Wilcox Formation
 
5

 
130

 
5,200

 
0.6
%
 
13
%
 
44
%

(a)
Committed and uncommitted tons represent in-place estimates. The projected extraction loss is approximately 10% of the proven and probable reserves, except with respect to the Eastern Undeveloped Mines, in which case the projected extraction loss is approximately 50% of the proven and probable reserves.
(b)
The Company's reserve estimates are generally based on the entire drill hole database for each reserve, which was used to develop a geologic computer model using triangulation methods and inverse distance to the second power as an interpolator for NACCO's reserves. As such, all reserves are considered proven (measured) within the Company's reserve estimate. None of the Company's coal reserves have been reviewed by independent experts. The Company’s estimate of the economic viability of the proven and probable reserve estimates for tons committed to customers pursuant to long-term contracts are supported by existing long-term contracts to mine coal on behalf of customers and life-of-mine plans associated with those contracts. The contracts with each customer of the Unconsolidated Mines eliminate Company exposure to spot coal market price fluctuations. At the Unconsolidated Mines, compensation from each customer to the Company includes reimbursement of all mine operating costs plus a contractually agreed fee based on the amount of coal delivered. Red Hills Mine - 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. MLMC is the exclusive supplier of coal to its customer’s power plant under its contract that runs through 2032. The Company’s assessment of the economic viability of the mineral reserves associated with MLMC takes into account estimated customer demand, including the minimum annual take provision in the contract, as well as cost of production. The economic viability of the uncommitted reserves assumes coal would be mined in a mine-mouth operation that minimizes or eliminates transportation costs and under contract terms, which are similar to those contained in the Company’s existing long-term management fee contracts, or leased to other miners. The majority of the Company’s uncommitted reserves are located in close proximity to power generation or other facilities, which could allow a mine-mouth operation. Lessees of this coal generally would mine the coal if the coal sale price would exceed the lessee operating costs. As to coal mined and sold by lessees, the Company would receive a royalty based on a percentage of the sale price. See footnote (h) for coal reserves currently leased to others.
(c)
The contracts for these mines require the customer to cover the cost of the ongoing replacement and upkeep of the plant and equipment of the mine.
(d)
Although the term of the existing coal sales agreement terminates in 2022, the term may be extended for three additional periods of five years, or until 2037, at the option of the Company.
(e)
These reserves are owned or controlled by customers. The Company conducts activities to extract these customer-owned and controlled reserves pursuant to long-term service contracts.

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(f)
These reserves are owned or controlled by Bisti's customer and it controls proven and probable reserve data. Bisti’s customer declined to allow us to include the proven and probable reserve data in this Form 10-K. The Company conducts activities to extract these customer-owned and controlled reserves pursuant to a long-term service contract.
(g)
Centennial ceased active mining operations at the end of 2015.
(h)
The proven and probable reserves included in the table do not include coal that is leased to others. The Company had 70.0 million tons and 71.4 million tons in 2019 and 2018, respectively, of Eastern Undeveloped Mines with leased coal committed under contract.

Unconsolidated Mines
Freedom Mine — The Coteau Properties Company
The Freedom Mine generally produces between 13.5 million and 14.5 million tons of lignite coal annually. The mine started delivering coal in 1983. All production from the mine is delivered to Dakota Coal Company, a wholly owned subsidiary of Basin Electric Power Cooperative. Dakota Coal Company then sells the coal to the Great Plains Synfuels Plant, Antelope Valley Station and Leland Olds Station, all of which are operated by affiliates of Basin Electric Power Cooperative.
The Freedom Mine, operated by Coteau, is located approximately 90 miles northwest of Bismarck, North Dakota. The main entrance to the Freedom Mine is accessed by means of a paved road and is located on County Road 15. Coteau holds 310 leases granting the right to mine approximately 33,599 acres of coal interests and the right to utilize approximately 22,939 acres of surface interests. In addition, Coteau owns in fee 33,525 acres of surface interests and 4,107 acres of coal interests. Substantially all of the leases held by Coteau were acquired in the early 1970s and have been replaced with new leases or have lease terms for a period sufficient to meet Coteau’s contractual production requirements.
The reserves are located in Mercer County, North Dakota, starting approximately two miles north of Beulah, North Dakota. The center of the basin is located near the city of Williston, North Dakota, approximately 100 miles northwest of the Freedom Mine. The economically mineable coal in the reserve occurs in the Sentinel Butte Formation, and is overlain by the Coleharbor Formation. The Coleharbor Formation unconformably overlies the Sentinel Butte Formation. It includes all of the unconsolidated sediments resulting from deposition during glacial and interglacial periods. Lithologic types include gravel, sand, silt, clay and till. The modified glacial channels are in-filled with gravels, sands, silts and clays overlain by till. The coarser gravel and sand beds are generally limited to near the bottom of the channel fill. The general stratigraphic sequence in the upland portions of the reserve area consists of till, silty sands and clayey silts.
Falkirk Mine — The Falkirk Mining Company
The Falkirk Mine generally produces between 7 million and 8 million tons of lignite coal annually primarily for the Coal Creek Station, an electric power generating station owned by Great River Energy. The mine started delivering coal in 1978. Commencing in the second half of 2014, Falkirk began delivering coal to Spiritwood Station, another electric power generating station owned by Great River Energy. Annual deliveries to Spiritwood Station have averaged between 200,000 and 400,000 tons.
The Falkirk Mine, operated by Falkirk, is located approximately 50 miles north of Bismarck, North Dakota on a paved access road off U.S. Highway 83. Falkirk holds 307 leases granting the right to mine approximately 45,997 acres of coal interests and the right to utilize approximately 24,300 acres of surface interests. In addition, Falkirk owns in fee 39,844 acres of surface interests and 1,270 acres of coal interests. Substantially all of the leases held by Falkirk were acquired in the early 1970s with initial terms that have been further extended by the continuation of mining operations.
The reserves are located in McLean County, North Dakota, from approximately nine miles northwest of the town of Washburn, North Dakota to four miles north of the town of Underwood, North Dakota. Structurally, the area is located on an intercratonic basin containing a thick sequence of sedimentary rocks. The economically mineable coals in the reserve occur in the Sentinel Butte Formation and the Bullion Creek Formation and are unconformably overlain by the Coleharbor Formation. The Sentinel Butte Formation conformably overlies the Bullion Creek Formation. The general stratigraphic sequence in the upland portions of the reserve area (Sentinel Butte Formation) consists of till, silty sands and clayey silts, main hagel lignite bed, silty clay, lower lignite of the hagel lignite interval and silty clays. Beneath the Tavis Creek, there is a repeating sequence of silty to sand clays with generally thin lignite beds.

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South Hallsville No. 1 Mine — The Sabine Mining Company
The South Hallsville No. 1 Mine generally produces between 2.5 million and 3.5 million tons of lignite coal annually. The mine started delivering coal in 1985. All production from the mine is delivered to Southwestern Electric Power Company's Henry W. Pirkey Plant.
The South Hallsville No. 1 Mine, operated by Sabine, is located approximately 150 miles east of Dallas, Texas on FM 968. The entrance to the mine is by means of a paved road. Sabine has no title, claim, lease or option to acquire any of the reserves at the South Hallsville No. 1 Mine. Southwestern Electric Power Company controls all of the reserves within the South Hallsville No. 1 Mine.
Five Forks Mine — Demery Resources Company, LLC
The Five Forks Mine, operated by Demery, began delivering coal in 2012 and is located approximately three miles north of Creston, Louisiana on State Highway 153. Access to the Five Forks Mine is by means of a paved road. Demery has no title, claim, lease or option to acquire any of the reserves at the Five Forks Mine. Demery's customer, Five Forks Mining, LLC, controls all of the reserves within the Five Forks Mine.
Marshall Mine — Caddo Creek Resources Company, LLC
The Marshall Mine, operated by Caddo Creek, began delivering coal in 2014 and is located approximately ten miles south of Marshall, Texas on FM-1186. Access to the Marshall Mine is by means of a paved road. Caddo Creek has no title, claim, lease or option to acquire any of the reserves at the Marshall Mine. Caddo Creek's customer, Marshall Mine, LLC, controls all of the reserves within the Marshall Mine.
Eagle Pass Mine — Camino Real Fuels, LLC

The Eagle Pass Mine, operated by Camino Real, began delivering coal in 2015 to Camino Real's customer, Dos Republicas Coal Partnership. The Eagle Pass Mine produces between 1.0 million and 2.0 million tons of bituminous coal annually.

Eagle Pass Mine is located approximately six miles north of Eagle Pass, Texas on State Highway 1588. Access to the Eagle Pass Mine is by means of a paved road. Camino Real has no title, claim, lease or option to acquire any of the reserves at the Eagle Pass Mine. Camino Real's customer, Dos Republicas Coal Partnership, controls all of the reserves within the Eagle Pass Mine.
Liberty Mine — Liberty Fuels Company, LLC

In 2017, Mississippi Power instructed Liberty to permanently cease all mining and delivery of lignite and to commence mine reclamation. The terms of the contract specified that Mississippi Power was responsible for all mine closure costs and Liberty receives compensation for providing mine reclamation services. As of December 31, 2019, the mine areas have been reclaimed and final mine reclamation activities, primarily monitoring, will continue until final bond release.
Coyote Creek Mine - Coyote Creek Mining Company, LLC

In 2016, the Coyote Creek Mine began delivering coal to the Coyote Station owned by Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Company and Northwestern Corporation. The Coyote Creek Mine generally produces approximately 1.5 million to 2.5 million tons of lignite coal annually when Coyote Station is operating at anticipated levels.

The Coyote Creek Mine is located approximately 70 miles northwest of Bismarck, North Dakota. The main entrance to the Coyote Creek Mine is accessed by means of a four-mile paved road extending west off of State Highway 49. Coyote Creek holds a sublease to 85 leases granting the right to mine approximately 7,809 acres of coal interests and the right to utilize approximately 15,168 acres of surface interests. In addition, Coyote Creek Mine owns in fee 160 acres of surface interests and has four easements to conduct coal mining operations on approximately 352 acres.

The reserves are located in Mercer County, North Dakota, starting approximately six miles southwest of Beulah, North Dakota. The center of the basin is located near the city of Williston, North Dakota, approximately 110 miles northwest of the Coyote Creek Mine. The economically mineable coal in the reserve occurs in the Sentinel Butte Formation, and is overlain by the Coleharbor Formation. The Coleharbor Formation unconformably overlies the Sentinel Butte Formation. It includes all of the unconsolidated sediments resulting from deposition during glacial and interglacial periods. Lithologic types include gravel, sand silt, clay and till. The modified glacial channels are in-filled with gravels, sands, silts and clays overlain by till. The coarser gravel and sand beds

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are generally limited to near the bottom of the channel fill. The general stratigraphic sequence in the upland portions of the reserve area consists of till, silty sands and clayey silts.
Navajo Mine - Bisti Fuels Company, LLC

Bisti has been the contract miner at NTEC's Navajo Mine since 2017. Bisti generally delivers approximately 5.0 million tons of sub-bituminus coal to the Four Corners Power Plant when the plant is operating at anticipated levels.

The Navajo Mine is located approximately 25 miles southwest of Farmington, New Mexico, off Indian Service Road 3005, and is on the Navajo Nation. Access to the Navajo Mine is by means of a paved road. Bisti has no title, claim, lease or option to acquire any of the reserves at Navajo Mine. NTEC, a wholly-owned limited liability company of The Navajo Nation, controls all of the reserves within the Navajo Mine.
Consolidated Mines
Red Hills Mine — Mississippi Lignite Mining Company
The Red Hills Mine generally produces between 2 million and 3 million tons of lignite coal annually. The Red Hills Mine started delivering coal in 2000. All production from the mine is delivered to its customer's Red Hills Power Plant.
The Red Hills Mine, operated by MLMC, is located approximately 120 miles northeast of Jackson, Mississippi. The entrance to the mine is by means of a paved road located approximately one mile west of Highway 9. MLMC owns in fee approximately 6,840 acres of surface interest and 3,950 acres of coal interests. MLMC holds leases granting the right to mine approximately 6,149 acres of coal interests and the right to utilize approximately 5,768 acres of surface interests. MLMC holds subleases under which it has the right to mine approximately 1,545 acres of coal interests. The majority of the leases held by MLMC were originally acquired during the mid-1970s to the early 1980s with terms extending 50 years, many of which can be further extended by the continuation of mining operations.
The lignite deposits of the Gulf Coast are found primarily in a narrow band of strata that outcrops/subcrops along the margin of the Mississippi Embayment. The potentially exploitable tertiary lignites in Mississippi are found in the Wilcox Group. The outcropping Wilcox is composed predominately of non-marine sediments deposited on a broad flat plain.
Centennial Natural Resources
Centennial ceased active mining operations at the end of 2015. Centennial and its affiliate, NACRC, own in fee approximately 5,602 acres of coal interests and approximately 2,323 acres of surface interests in Alabama. Centennial holds leases in Alabama granting the right to mine approximately 7,269 acres of coal interests and the right to utilize approximately 8,535 acres of surface interests. The majority of the leases held by Centennial were originally acquired between 2000 and 2012 with terms that can be extended by the continuation of mining activities.

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North American Mining
NAMining primarily operates and maintains draglines to mine limestone and sand at the following mines in Florida and Virginia pursuant to mining services agreements with the mine owners:
Location Name
Location
Customer
Year NACCO Started Operations
White Rock — North
Miami
WRQ
1995
Krome
Miami
Cemex
2003
Alico
Ft. Myers
Cemex
2004
FEC
Miami
Cemex
2005
White Rock — South
Miami
WRQ
2005
SCL
Miami
Cemex
2006
Card Sound
Florida City
Cemex
2009
Central State Aggregates
Zephyrhills
McDonald Group
2016
Mid Coast Aggregates
Sumter County
McDonald Group
2016
West Florida Aggregates
Hernando County
McDonald Group
2016
St. Catherine
Sumter County
Cemex
2016
Center Hill
Sumter County
Cemex
2016
Inglis
Crystal River
Cemex
2016
Titan Corkscrew
Ft. Myers
Titan America
2017
Palm Beach Aggregates
Loxahatchee
Palm Beach Aggregates
2017
Perry
Lamont
Martin Marietta
2018
SDI Aggregates
Florida City
Blue Water Industries
2018
Queensfield
King William County, VA
King William Sand and Gravel Company, Inc.
2018
County Line
Pasco County
K&M Pasco 130 Holdings, LLC
2019
Newberry
Alachua County
Argos USA, LLC
2019
NAMining's customers control all of the limestone and sand reserves within their respective mines.
Access to the White Rock mine is by means of a paved road from 122nd Avenue.
Access to the Krome mine is by means of a paved road from Krome Avenue.
Access to the Alico mine is by means of a paved road from Alico Road.
Access to the FEC mine is by means of a paved road from NW 118th Avenue.
Access to the SCL mine is by means of a paved road from NW 137th Avenue.
Access to the Card Sound mine is by means of a paved road from SW 408th Street.
Access to the Central State Aggregates mine is by means of a paved road from Yonkers Boulevard.
Access to the Mid Coast Aggregates mine is by means of a paved road from State Road 50.
Access to the West Florida mine is by means of a paved road from Cortez Boulevard.
Access to the St. Catherine mine is by means of a paved road from County Road 673.
Access to the Center Hill mine is by means of a paved road from West Kings Highway.
Access to the Inglis mine is by means of a paved road from Highway 19 South.
Access to the Titan Corkscrew mine is by means of a paved road from Corkscrew Road.
Access to the Palm Beach Aggregates mine is by means of a paved road from State Road 80.
Access to the Perry mine is by means of paved road from Nutall Rise Road.
Access to the SDI Aggregates mine is by means of paved road from SW 167th AVE.

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Access to the Queensfield Mine is by means of paved road from Dabney's Mill Road (SR 604).
Access to the County Line mine is by means of paved road from 18744 County Line Road.
Access to the Newberry mine is by means of paved road from NW County Road 235 (CR 235).
NAMining has no title, claim, lease or option to acquire any of the reserves at any of the mines where it provides services.
General Information
Leases. The leases held by Coteau, Coyote Creek, Falkirk and MLMC have a variety of continuation provisions, but generally permit the leases to be continued beyond their fixed terms. Centennial holds the mining rights to the reserves within its mines through fee ownership, and leases and licenses from the coal and surface owners. NACCO expects coal will be available to meet customers' future production requirements utilizing land and reserves that are currently owned or leased or accessible through ownership acquisition or new leases.
Previous Operators. There were no previous operators of the Freedom Mine, Falkirk Mine, South Hallsville No. 1 Mine, Five Forks Mine, Marshall Mine, Eagle Pass Mine, Liberty Mine, Coyote Creek Mine or Red Hills Mine. NTEC's Navajo Mine was previously operated by a third party.
Exploration and Development. All coal mines are well past the exploration stage. With the exceptions of Centennial and Liberty, additional pit development is under way at each mine. Drilling programs are routinely conducted for the purpose of refining guidance related to ongoing operations. For example, at the Red Hills Mine, the lignite coal reserve has been defined by a drilling program that is designed to provide 500-foot spaced drill holes for areas anticipated to be mined within six years of the current pit. Drilling beyond the six-year horizon ranges from 1,000 to 2,000-foot centers. Drilling is conducted annually to stay current with the advance of mining operations. Geological evaluation is in process at all operating locations.
Facilities and Equipment. The facilities and equipment for each of the coal mines are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, the mines evaluate what
replacement option will be the most cost-efficient, including the evaluation of both new and used equipment, and proceed with that replacement. The majority of electrical power for the draglines, shovels, coal crushers, coal conveyors and facilities generally is provided by the power generation customer for the applicable mine. Electrical power for the Sabine facilities is provided by Upshur Rural Electric Co-op. Electrical power for the Sabine dragline operating in the South Marshall permit area is provided by Southwestern Electric Power Company. Electrical power for the draglines operating in Sabine's Rusk permit area is provided by Rusk County Electric Co-op. Electrical power for the MLMC draglines and shovels is provided by 4-County Electric Power Association. The remainder of the equipment generally is powered by diesel fuel or gasoline.


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The mining method and total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2019 is set forth in the chart below:
Location
 
Mining Method
 
Total Historical Cost of Mine
Property, Plant and Equipment
(excluding Coal Land, Real Estate
and Construction in Progress), Net of
Applicable Accumulated
Amortization, Depreciation and Impairment
 
 
 
 
(in millions)
Unconsolidated Mining Operations
 
 
 
 
Freedom Mine — The Coteau Properties Company
 
Dragline operation with 3 draglines
 
$
86.6

Falkirk Mine — The Falkirk Mining Company
 
Dragline operation with 4 draglines
 
$
49.0

South Hallsville No. 1 Mine — The Sabine Mining Company
 
Dragline operation with 4 draglines
 
$
113.7

Five Forks Mine — Demery Resources Company, LLC
 
Truck-shovel operation
 
$

Marshall Mine — Caddo Creek Resources Company, LLC
 
Dragline operation with 1 dragline
 
$

Eagle Pass Mine — Camino Real Fuels, LLC
 
Truck-shovel operation
 
$

 
 
 
 
 
Coyote Creek Mine — Coyote Creek Mining Company, LLC
 
Dragline operation with 1 dragline
 
$
149.9

Navajo Mine — Bisti Fuels Company, LLC
 
Dragline operation with 2 draglines
 
$

Consolidated Mining Operations
 
 
 
 
Red Hills Mine — Mississippi Lignite Mining Company
 
Dragline operation with 1 dragline
 
$
57.8

NAMining
 
(a)
 
$
10.9

Other
 
N/A
 
$
1.2

(a) During 2019, NAMining operated 31 draglines at 20 quarries. Of the 31 draglines, 5 are owned by the Company and 26 are owned by customers. The mining process at the limestone mines involves excavating limestone from a water-filled quarry utilizing draglines. The excavated limestone is transported and processed by the customer.
Predominantly all of Bisti, Caddo Creek, Camino Real and Demery's machinery and equipment is owned by the customer of the respective mines.

All of the Company’s coal mines are surface mines that are located adjacent to, or nearby, the customer’s power plant, synfuels plant or activated carbon facility. Overburden, the material between the surface of the land and the coal seam, is removed using draglines, dozers and/or trucks and shovels, including electric rope shovels. Coal is then extracted and loaded onto haul trucks using surface miners, excavators, dozers, scrapers, backhoes and other machinery and equipment. Coal is taken to a stockpile or delivered directly to customers via conveyor or short haul rail. After mining, draglines and/or trucks and shovels are used to backfill the overburden that was removed at the beginning of the process to allow for site reclamation.

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 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.
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, Caddo Creek, Bisti and Camino Real, 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 Caddo Creek, Demery, Bisti and Camino Real; however, the Company cannot be certain that these third parties will be able to maintain all such permits in the future.

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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.
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"); 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.
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. With the exception of the Navajo Nation in New Mexico, which is directly regulated by the Office of Surface Mining Reclamation and Enforcement ("OSMRE") under their Indian Lands Program, all of the states where the Company has active coal mining operations have achieved primary control of enforcement through federal authorization under SMCRA.
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 fee is currently $0.08 per ton on lignite coal produced and $0.28 per ton on other surface-mined coal.
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 unfunded, with the exception of the final mine closure costs for the Coyote Creek Mine, which are being funded throughout the production stage.

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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 are 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.
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.

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

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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. SIPs will be required by July 31, 2021.

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 is proposing to clarify the process for evaluating whether the New Source Review (NSR) permitting program would apply to proposed projects at existing air pollution sources. This proposal would make 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”. This clarification is expected to be finalized in 2020. The remaining litigation and the uncertainty around the New Source Review 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. In addition, the Company's power generation customers may choose to close coal-fired generation units or to postpone or cancel plans to add new capacity, in light of these costs and the limited time available for compliance with the requirements and the prospects of the imposition of additional future requirements on emissions from coal-fired units. 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 this finding, the EPA published a New Source Performance Standard for greenhouse gases, emitted from future new power plants. In 2019, the EPA issued the Affordable Clean Energy ("ACE") Rule to reduce greenhouse gas emissions from existing electric generating units ("EGUs"). In contrast to the Clean Power Plan, the ACE rule limits "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. Under ACE, states have the primary role in developing standards of performance that result from the application of BSER. The EPA has not provided a standard of performance that it will deem presumptively acceptable in a state plan, but urges states to provide full justification for each component of their plans so that the EPA can evaluate BSER on a unit-by-unit basis.

States have until 2022 to develop and submit compliance plans to the EPA. The EPA will have a year to review and approve the plans. The states are given 24 months from the approval date to implement the rule and can extend the compliance schedule for units that meet progress milestones. An EGU’s compliance with the ACE rule may not be required until 2024 or later. Until states develop plans that are accepted by the EPA, the Company will not be able to determine the final impact of the rule.

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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 2019, the United States submitted a formal notification of its withdrawal from the Paris Agreement. 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-fueled 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 us 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.

Bellaire Corporation, a wholly owned non-operating subsidiary of the Company (“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. The EPA is currently proposing additional changes to the CCR rule that would affect annual groundwater monitoring reporting requirements, environmental demonstration threshold, temporary placement of unencapsulated CCR on the land, and establish a new deadline for all unlined/non-compliant surface impoundments.These may raise the cost for CCR disposal at coal-fired power plants, making them less competitive, and may have an adverse impact on demand for coal.
The EPA rule exempts CCRs disposed of 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 disposing of CCRs from its customers may decrease and its costs may increase due to the purchase of alternative materials for beneficial uses.
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.


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INFORMATION ABOUT OUR EXECUTIVE OFFICERS
The following tables set forth as of March 1, 2020 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. Certain executive officers of the Company listed below are also executive officers for NACoal.
EXECUTIVE OFFICERS OF THE COMPANY
Name
 
Age
 
Current Position
 
Other Positions
J.C. Butler, Jr.
 
59

 
President and Chief Executive Officer of NACCO (from September 2017) and President and Chief Executive Officer of NACoal (from July 2015)
 
From prior to 2015 to September 2017, Senior Vice President - Finance, Treasurer and Chief Administrative Officer of NACCO. From prior to 2015 to September 2017, Assistant Secretary of Hamilton Beach Brands ("HBB") and Kitchen Collection ("KC"). From prior to 2015 to July 2015, Senior Vice President - Project Development, Administration and Mississippi Operations of NACoal.
 
 
 
 
 
 
 
Matthew J. Dilluvio
 
30

 
Associate Counsel and Assistant Secretary of NACCO and NACoal (from June 2019)
 
From October 2016 to May 2019, Associate, Sidley Austin LLP (law firm). From prior to 2015 to September 2016, Associate, White and Case LLP (law firm).
 
 
 
 
 
 
 
Elizabeth I. Loveman
 
50

 
Vice President and Controller and Principal Financial Officer (from prior to 2015)
 
 
 
 
 
 
 
 
 
John D. Neumann
 
44

 
Vice President, General Counsel and Secretary of NACCO, Vice President, General Counsel and Secretary of NACoal (from prior to 2015)
 
From prior to 2015 to September 2017, Assistant Secretary of HBB and KC.
 
 
 
 
 
 
 
Miles B. Haberer
 
53

 
Associate General Counsel of NACCO (from prior to 2015), Associate General Counsel, Assistant Secretary of NACoal (from prior to 2015) and President, North American Coal Royalty Company (an NACoal subsidiary) (from September 2015)    
                                                        

 
From prior to 2015 to September 2015, Director-Land of NACoal. From prior to 2015 to September 2015, Assistant Secretary of NACCO. 

 
 
 
 
 
 
 
Sarah E. Fry
 
44

 
Associate General Counsel and Assistant Secretary of NACCO (from May 2017), Associate General Counsel and Assistant Secretary of NACoal (from May 2017)
 
From January 2015 to April 2017, Senior Counsel, Locke Lord (law firm).
 
 
 
 
 
 
 
Thomas A. Maxwell
 
42

 
Vice President - Financial Planning and Analysis and
Treasurer (from September 2017)


 
From September 2015 to September 2017, Director of Financial Planning and Analysis and Assistant Treasurer.
From January 2014 to September 2015, Senior Manager, Finance and Assistant Treasurer.
PRINCIPAL OFFICERS OF THE COMPANY’S SUBSIDIARIES
Name
 
Age
 
Current Position
 
Other Positions
Eric A. Dale
 
45

 
Treasurer and Senior Director, Financial Planning and Analysis, of NACoal (from January 2017)
 
From prior to 2015 to November 2016, Vice President of Financial Planning and Analysis at Westmoreland Coal Company.
 
 
 
 
 
 
 
Carroll L. Dewing
 
63

 
Vice President - Operations of NACoal (from January 2017)
 
From prior to 2015 to December 2016, President, The Coteau Properties Company (an NACoal subsidiary).
From prior to 2015 to December 2016, Vice President - North Dakota, Texas and Florida Operations, Human Resources and External Affairs of NACoal.
 
 
 
 
 
 
 
Andrew B. Hart
 
41
 
Controller of NACoal (from September 2019)
 
From November 2017 to August 2019, Assistant Controller of NACoal. From prior to 2015 to October 2017, Assistant Controller at Rowan Companies, plc.
 
 
 
 
 
 
 
LaVern K. Lund
 
47

 
Vice President - Engineering and Business Development (from April 2019)
 
From May 2017 to March 2019, Vice President - Business Development. From prior to 2015 to April 2017, President of Liberty.
 
 
 
 
 
 
 
J. Patrick Sullivan, Jr.


 
61

 
Vice President and Chief Financial Officer of NACoal (from prior to 2015)
 
 


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Item 1A. RISK FACTORS
Termination of or default under long-term mining contracts could materially reduce the Company's profitability.
Substantially all of the Coal Mining segment's profits are derived from long-term mining contracts. Although the Company has long-term contracts, numerous political and regulatory authorities, along with well-funded 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. As a result of such activities, the Coal Mining segment's customers could prematurely retire certain coal-fired generating units. Any customers' premature plant closure could have a material adverse effect on the Company’s business, financial condition and results of operations.
During the first quarter of 2020, Great River Energy, Falkirk's customer, announced that it was evaluating the economics of the Coal Creek Station ("CCS") power plant. The Company has a mining contract to supply coal to CCS that expires in 2045. Any decision by Great River Energy to reduce operations or prematurely close CCS would have a material adverse effect on the Company’s results of operations.
The loss of, or significant reduction in, purchases by our largest coal customers could adversely affect our business, financial condition, results of operation and cash flows.
For the year ended December 31, 2019, the Coal Mining segment derived approximately 60% of earnings of unconsolidated operations from two customers, Basin Electric Power Cooperative and Great River Energy. 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 largest 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 largest customers experience declining demand due to market, economic 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 their purchases of coal from us, the Company's business, financial condition, results of operations and cash flows could be adversely affected.
Mississippi Lignite Mining Company ("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 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 would adversely affect the Company's operating results and could result in significant impairments. In addition, MLMC sells lignite at contractually agreed upon prices which are subject to changes in the level of established indices over time. The price of diesel fuel is heavily-weighted among these indices. As such, a substantial decline in diesel prices could materially reduce MLMC's profitability, as the decline in revenue will only be partially offset by the effect of lower diesel prices on production costs.
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 ("IRP"). The IRP indicates TVA 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. TVA has dispatched Red Hills Power Plant at a lower rate in the last two years than in prior years.
Choctaw Generation Limited Partnership ("CGLP") leases the Red Hills Power Plant from a Southern Company subsidiary pursuant to a leveraged lease arrangement. The ability of the lessee to make required payments to the Southern Company subsidiary is dependent on the operational performance of the Red Hills Power Plant. Southern Company recently publicly disclosed that while all CGLP lease payments have been paid in full through December 31, 2019, operational and other risks have resulted in cash liquidity challenges at the Red Hills Power Plant, and based on current forecasts of energy prices in the years following the expiration of the PPA in 2032, concerns exist regarding the lessee's ability to make the remaining semi-annual lease payments through the end of the lease term in 2047. Southern Company concluded that it is no longer probable that all of the payments will be received over the term of the lease and therefore recognized an impairment charge in the fourth quarter of 2019. 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

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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.
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 or 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, 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 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 and coal mining industry that affect our customers could also adversely affect the Company. Lower natural gas prices and increased availability of renewables have 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.
A decrease in coal consumption by the electric power generation industry and the Company’s customers 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, 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 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

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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 14 in this Form 10-K for further discussion.
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 and the Affordable Clean Energy Rule 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, ACE 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 ACE 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 promulgated or proposed 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 14 in this Form 10-K for further discussion.
The Company has experienced growth in its NAMining business in recent periods and it may not be able to sustain 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 in expanding business development capabilities outside of Florida and in providing 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 effectively, the Company may not be able to take advantage of market opportunities. 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.
Property and casualty insurance is increasingly expensive, contains more stringent terms and may be difficult to obtain in the future.
Property and casualty insurance coverage is expensive and from time to time may be difficult or impossible to obtain. The Company's insurance policies are subject to annual review by its insurers and policies may not be renewed at all or on similar or favorable terms. Because the Company is involved in the coal mining industry, insurance carriers may decide not to insure us in the future. In addition, if the Company makes significant insurance claims, its ability to obtain future insurance coverage at commercially reasonable rates could be materially adversely affected. An inability to obtain property and casualty insurance, significant increases in the cost of insurance the Company obtains, or losses in excess of its liability insurance coverage, could have a material adverse effect on the Company's operating results and financial condition.

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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 interests and royalty interests in seven states 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 and, to a lesser extent, oil and coal. In recent years, a significant portion of the Minerals Management segment's income has been derived from lease signing bonus and production payments associated with assets in the Utica Shale in Ohio and future royalty-based income is dependent on the number of gas wells being developed and operated on the Company’s mineral acreage in Ohio.  See “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 30 in this Form 10-K for further discussion. 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, 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. 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. In addition to the natural production decline curve, royalty income can fluctuate 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 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. Any of these risks could materially reduce the Company’s expected royalty income and the Company’s profitability.
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, adverse mining conditions, unexpected maintenance problems and shortages of replacement parts, which could significantly reduce the Company's profitability.
The Coal Mining Segment's customer's operations require significant capital expenditures
Maintaining power plants requires significant capital expenditures. Any delay or reduction in making capital expenditures to maintain or upgrade coal-fired power plants by the 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.
Long-lived and intangible assets could become impaired.
The Company reviews long-lived assets, including property, plant and equipment and amortizing intangible assets, for impairment whenever changes in circumstances or events may indicate that the carrying amounts are not recoverable. Factors which may cause an impairment of long-lived assets include significant changes in the manner of use of these assets, negative industry or market trends, significant underperformance relative to historical or projected future operating results, or a likely sale or disposal of the asset before the end of its estimated useful life.
The Company is subject to the high costs and 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 costs and 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.
Estimates of the Company's recoverable coal reserves involve uncertainties, and inaccuracies in these estimates could result in lower than expected revenues, higher than expected costs, decreased profitability and asset impairments.
The Company estimates recoverable coal reserves based on engineering and geological data assembled and analyzed by internal and, less frequently, external engineers and geologists. The Company's estimates as to the quantity and quality of the coal in its reserves are updated annually to reflect production of coal from the reserves and new drilling, engineering or other data. These estimates depend upon a variety of factors and assumptions, many of which involve uncertainties and factors

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beyond the Company's control, such as geological and mining conditions that may not be fully identified by available exploration data or that may differ from experience in current operations.
For these reasons, estimates of the recoverable quantities and qualities attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of net cash flows expected from particular reserves may vary substantially. In addition, coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to the Company's reserves may vary materially from estimates. Accordingly, the Company's estimates may vary from the actual reserves. Any inaccuracy in the reserve estimates could result in lower than expected revenues, higher than expected costs, decreased profitability and asset impairments.
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.
Certain U.S. federal income tax deductions currently available with respect to coal mining and production may be eliminated.
From time to time, legislation is proposed that could result in the reduction or elimination of certain U.S. federal income tax provisions currently available to companies engaged in the exploration, development, and production of coal reserves, including the percentage depletion allowance with respect to coal properties. No legislation with that effect has been proposed, but the elimination of those provisions would have a material adverse effect on the Company’s business, financial condition and results of operations.
Certain of the Coal Segment’s customers 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 being less economical than other sources of power generation, which could reduce demand and result in a decrease in coal consumption. A decrease in coal consumption by the Company’s customers could have a material adverse effect on the Company’s business, financial condition and results of operations.
The Company’s business could suffer if NACCO’s information technology systems are disrupted, cease to operate effectively or if the Company experiences a security breach, a cyber incident or cyber attack.
The Company relies on information technology systems to operate its business and to record and process transactions; respond to customer inquiries; purchase supplies; deliver inventory on a timely basis; and maintain cost-efficient operations. Despite the Company's efforts, the Company’s information technology systems may be vulnerable from time to time to damage or interruption from computer viruses, power outages, third-party intrusions and other technical malfunctions.
Through the Company’s business operations, the Company collects and stores confidential information from its customers and vendors and personal information and other confidential information from its employees. Although the Company has taken steps designed to safeguard such information, there can be no assurance that such information will be protected against unauthorized access, use or disclosure. Unauthorized parties may penetrate the Company’s or its vendors’ network security and, if successful, misappropriate such information. Additionally, methods to obtain unauthorized access to confidential information change frequently and may be difficult to detect, which can impact the Company’s ability to respond appropriately.
The Company could be subject to liability for failure to comply with privacy and information security laws, for failing to protect personal information or for failing to respond appropriately. Loss, unauthorized access to, or misuse of confidential or personal information could disrupt the Company’s operations, damage the Company’s reputation, and expose the Company to claims from customers, financial institutions, regulators, employees and other persons, any of which could have an adverse effect on the Company’s business, financial condition and results of operations.

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Security breaches, cyber incidents or cyber attacks could include, among other things, computer viruses, malicious or destructive code, ransomware, social engineering attacks (including phishing and impersonation), hacking, denial of service attacks and other attacks.
Like many other companies, the Company is the target of malicious cyber-attack attempts in the normal course of business. Cybersecurity incidents involving businesses and other institutions are on the rise. Cyber threats are rapidly evolving and those threats and the means for obtaining access to information in digital and other storage media are becoming increasingly sophisticated. Cyber threats and cyber-attackers can be sponsored by nation states or sophisticated criminal organizations or be the work of hackers.
As cyber threats evolve and become more difficult to detect and successfully defend against, one or more cyber-attacks might defeat the Company's or a third-party service provider's security measures in the future. Employee error or other irregularities may also result in a failure of security measures and a breach of information systems. Moreover, hardware, software or applications the Company may use have inherent defects of design, manufacture or operations or could be inadvertently or intentionally implemented or used in a manner that could compromise information security.
A security breach and loss of information may not be discovered for a significant period of time after it occurs. Any compromise of data security could result in a violation of applicable privacy and other laws or standards, the loss of valuable business data, or a disruption of the Company's business. A security breach involving the misappropriation, loss or other unauthorized disclosure of sensitive or confidential information could give rise to unwanted media attention, materially damage customer relationships and the Company's reputation, and result in fines, fees, or liabilities, which may not be covered by insurance policies. The Company is continuously installing new and upgrading existing information technology systems. The Company uses employee awareness training around phishing, malware, and other cyber risks. The Company believes these incidents are likely to continue and is unable to predict the direct or indirect impact of future attacks or breaches to business operations.
The Company is dependent on key personnel and the loss of these key personnel could significantly reduce its profitability.
The Company is highly dependent on the skills, experience and services of its key personnel and the loss of key personnel could have a material adverse effect on its business, operating results and financial condition. Employment and retention of qualified personnel is important to the successful conduct of the Company's business. Therefore, the Company's success also depends upon its ability to recruit, hire, train and retain skilled and experienced management personnel. The Company's inability to hire and retain personnel with the requisite skills could impair its ability to manage and operate its business effectively and could significantly reduce its profitability.
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, contractual limitations 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.

The Company’s operations could be disrupted by natural or human causes beyond its control

The Company’s operations are subject to disruption from natural or human causes beyond its control, including physical risks from hurricanes, severe storms, floods and other forms of severe weather, accidents, fires, earthquakes, terrorist acts and epidemic or pandemic diseases such as the coronavirus, any of which could result in suspension of operations or harm to people or the environment. While all of the Company’s operations are located in the United States, the Company participates in a global supply chain, and if a disease spreads sufficiently to cause a pandemic (or to cause the fear of a pandemic to rise) or governments regulate or restrict the flow of labor or products or impede the travel of Company personnel, the Company’s ability to conduct normal business operations could be impacted which could adversely affect the Company’s results of operations and liquidity.
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

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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 by the Company 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; (v) announcements concerning NACCO or its competitors; (vi) lack of trading liquidity; 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 our 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.
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 us, 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 effect 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 our common stock less attractive because of these exemptions. If some investors find NACCO's common stock less attractive as a result, there may be a less active trading market for the Company's common stock and the stock price may be more volatile.
The Company may be subject to risk relating to increasing cash requirements of certain employee benefits plans, which may affect its financial position.
Although as of December 31, 2019, the Company's consolidated defined benefit pension plans are frozen and no longer provide for the accrual of future benefits, the expenses recorded for, and cash contributions required to be made to its defined benefit pension plans are dependent on changes in market interest rates and the value of plan assets, which are dependent on actual investment returns. Significant changes in U.S. pension funding regulations, market interest rates, decreases in the value of plan assets or investment losses on plan assets may require the Company to increase the cash contributed to defined benefit pension plans which may affect its financial position.

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The Company may become subject to claims under foreign laws and regulations, which may be expensive, time consuming and distracting.
The Company is subject to the laws and the court systems of multiple jurisdictions. The Company may become subject to claims outside the U.S. for violations or alleged violations of laws with respect to past or future foreign operations of NACCO. In addition, these laws may be changed or new laws may be enacted in the future. International litigation is often expensive, time consuming and distracting. As a result, any of these risks could significantly reduce the Company's profitability and its ability to operate its businesses effectively.
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, 2019, 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, 2019, accounted for the remaining voting power of the Company. As of December 31, 2019, 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 82 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.

Item 1B. UNRESOLVED STAFF COMMENTS
None.

Item 2. PROPERTIES
NACCO leases office space in Mayfield Heights, Ohio, a suburb of Cleveland, Ohio, which serves as its corporate headquarters.

NACoal leases its corporate headquarters office space in Plano, Texas.
NAMining leases office and warehouse space in Medley, Florida.
Proven and probable coal reserves and deposits are estimated at approximately 2.0 billion tons (including the Unconsolidated Subsidiaries), all of which are lignite coal deposits, except for approximately 84.0 million tons of bituminous coal. Reserves are estimates of quantities of coal, made by the Company's geological and engineering staff, which are considered mineable in the future using existing operating methods. Developed reserves are those which have been allocated to mines which are in operation; all other reserves are classified as undeveloped. Information concerning mine type, reserve data and coal quality characteristics are set forth on the table on pages 7 and 8 under “Item 1. Business.”

Item 3. LEGAL PROCEEDINGS
Neither the Company nor any of its subsidiaries is a party to any material legal proceeding other than ordinary routine litigation incidental to its respective business.

Item 4. MINE SAFETY DISCLOSURES
Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of The Dodd-Frank Act and Item 104 of Regulation S-K is included in Exhibit 95 filed with this Form 10-K.


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PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
NACCO's Class A common stock is traded on the New York Stock Exchange under the ticker symbol “NC.” Because of transfer restrictions, no trading market has developed, or is expected to develop, for the Company's Class B common stock. The Class B common stock is convertible into Class A common stock on a one-for-one basis.
At December 31, 2019, there were 708 Class A common stockholders of record and 139 Class B common stockholders of record.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Issuer Purchases of Equity Securities (1)
 
Period
(a)
Total Number of Shares Purchased
 
(b)
Average Price Paid per Share
 
(c)
Total Number of Shares Purchased as Part of the Publicly Announced Program
 
(d)
Maximum Number of Shares (or Approximate Dollar Value) that May Yet Be Purchased Under the Program (1)
 
October 1 to 31, 2019

 
$

 

 
$
22,295,747

 
November 1 to 30, 2019
23,959

 
$
47.94

 
23,959

 
$
24,114,170

(1) 
December 1 to 31, 2019
9,562

 
$
47.28

 
9,562

 
$
23,662,079

 
     Total
33,521

 
$
47.75

 
33,521

 
$
23,662,079

 

(1)
On November 6, 2019, the Company's Board of Directors approved a stock purchase program ("2019 Stock Repurchase Program") providing for the purchase of up to $25.0 million of the Company’s outstanding Class A Common Stock through December 31, 2021. NACCO’s previous repurchase program would have expired on December 31, 2019 but was terminated and replaced by the 2019 Stock Repurchase Program. See Note 12 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's stock repurchase programs.

Item 6. SELECTED FINANCIAL DATA

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




 





29


Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)





OVERVIEW
Management's Discussion and Analysis of Financial Condition and Results of Operations include NACCO Industries, Inc.® (the "parent company" or “NACCO”) and its wholly owned subsidiaries (collectively, the “Company”). NACCO is the public holding company for The North American Coal Corporation®.  The North American Coal Corporation and its affiliated companies (collectively, “NACoal”) operate in the mining and natural resources industries through three operating segments: Coal Mining, North American Mining ("NAMining") and Minerals Management. The Coal Mining segment operates surface coal mines under long-term contracts with power generation companies and activated carbon producers pursuant to a service-based business model. The NAMining segment provides value-added contract mining and other services for producers of aggregates, lithium and other minerals. The Minerals Management segment promotes the development of the Company’s oil, gas and coal reserves, generating income primarily from royalty-based lease payments from third parties.

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

Management's Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are based upon management's current expectations and are subject to various uncertainties and changes in circumstances. Important factors that could cause actual results to differ materially from those described in these forward-looking statements are set forth below under the heading “Forward-Looking Statements."
All financial statement line items below operating profit (other income, including interest expense and interest income, the provision for income taxes and net income) are presented and discussed within this Form 10-K on a consolidated basis. Included within other income on the line Income from other unconsolidated affiliates is the financial results of NoDak Energy Services, LLC ("NoDak"). NoDak operates and maintains a coal drying system at a customer’s power plant. The NoDak contract expired in the first quarter of 2020.

See “Item 1. Business" beginning on page 1 in this Form 10-K for further discussion of NACCO's subsidiaries. Additional information relating to financial and operating data on a segment basis (including unallocated items) is set forth in Note 15 to the Consolidated Financial Statements contained in this Form 10-K.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The Company's discussion and analysis of its financial condition and results of operations are based upon the Company's consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities (if any). On an ongoing basis, the Company evaluates its estimates based on historical experience, actuarial valuations and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from those estimates.
The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of its consolidated financial statements.
Revenue recognition: Revenues are recognized when control of the promised goods or services is transferred to the Company’s customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The Company accounts for revenue in accordance with Accounting Standards Codification ("ASC") Topic 606, "Revenue from Contracts with Customers", which NACCO adopted on January 1, 2018, using the modified retrospective method. See Note 3 to the Consolidated Financial Statements in this Form 10-K for further discussion of the impact of ASC 606 on the Company's revenue recognition.


30


Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)





Accounting for Asset Retirement Obligations: The Company's asset retirement obligations are principally for costs to close its surface mines and reclaim the land it has disturbed as a result of its normal mining activities as well as for costs to dismantle certain mining equipment at the end of the life of the mine. Under certain federal and state regulations, the Company is required to reclaim land disturbed as a result of mining. The Company determined the amounts of these obligations based on cost estimates, adjusted for inflation, projected to the estimated closure dates, and then discounted using a credit-adjusted risk-free interest rate. Changes in any of these estimates could materially change the Company's estimates for these asset retirement obligations causing a related increase or decrease in reported net operating results in the period of change in the estimate. The accretion of the liability is being recognized over the estimated life of each individual asset retirement obligation. The Company has capitalized an asset’s retirement cost as part of the cost of the related long-lived asset. These capitalized amounts are subsequently amortized to expense using a systematic and rational method.
Bellaire is a non-operating subsidiary of the Company with legacy liabilities relating to closed mining operations, primarily former Eastern U.S. underground coal mining operations. These legacy liabilities include obligations for water treatment and other environmental remediation that arose as part of the normal course of closing these underground mining operations. The Company determined the amounts of these obligations based on cost estimates, adjusted for inflation, and then discounted using a credit-adjusted risk-free interest rate. The accretion of the liability is recognized over the estimated life of the asset retirement obligation. Since Bellaire's properties are no longer active operations, no associated asset has been capitalized.
Changes in any of these estimates could materially change the Company's estimates for these asset retirement obligations causing a related increase or decrease in reported net operating income in the period of change in the estimate. See Note 7 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's asset retirement obligations.
Long-lived assets: The Company periodically evaluates long-lived assets for impairment when changes in circumstances or the occurrence of certain events indicate the carrying amount of an asset may not be recoverable. Upon identification of indicators of impairment, the Company evaluates the carrying value of the asset by comparing the estimated future undiscounted cash flows generated from the use of the asset and its eventual disposition with the asset's net carrying value. If the carrying value of an asset is considered impaired, an impairment charge is recorded for the amount that the carrying value of the long-lived asset exceeds its fair value. Fair value is estimated as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
Income taxes: Tax law requires certain items to be included in the tax return at different times than the items are reflected in the financial statements. Some of these differences are permanent, such as expenses that are not deductible for tax purposes, and some differences are temporary, reversing over time, such as depreciation expense. These temporary differences create deferred tax assets and liabilities using currently enacted tax rates. The objective of accounting for income taxes is to recognize the amount of taxes payable or refundable for the current year, and deferred tax liabilities and assets for the future tax consequences of events that have been recognized in the financial statements or tax returns. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the provision for income taxes in the period that includes the enactment date. Management is required to estimate the timing of the recognition of deferred tax assets and liabilities, make assumptions about the future deductibility of deferred tax assets and assess deferred tax liabilities based on enacted laws and tax rates for the appropriate tax jurisdictions to determine the amount of such deferred tax assets and liabilities. Changes in the calculated deferred tax assets and liabilities may occur in certain circumstances, including statutory income tax rate changes, statutory tax law changes, or changes in the structure or tax status.
The Company's tax assets, liabilities, and tax expense are supported by historical earnings and losses and the Company's best estimates and assumptions of future earnings. The Company assesses whether a valuation allowance should be established against its deferred tax assets based on consideration of all available evidence, both positive and negative, using a more likely than not standard. This assessment considers, among other matters, scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. The assumptions about future taxable income require significant judgment and are consistent with the plans and estimates the Company is using to manage the underlying businesses. When the Company determines, based on all available evidence, that it is more likely than not that deferred tax assets will not be realized, a valuation allowance is established.
Since significant judgment is required to assess the future tax consequences of events that have been recognized in the Company's financial statements or tax returns, the ultimate resolution of these events could result in adjustments to the Company's financial statements and such adjustments could be material. The Company believes the current assumptions, judgments and other considerations used to estimate the current year accrued and deferred tax positions are appropriate. If the actual outcome of future tax consequences differs from these estimates and assumptions, due to changes or future events, the

31


Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)





resulting change to the provision for income taxes could have a material impact on the Company's results of operations and financial position.
See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's income taxes.
 
CONSOLIDATED FINANCIAL SUMMARY

The results of operations for NACCO were as follows for the years ended December 31:
 
2019
 
2018
Revenues:
 
 
 
   Coal Mining
$
68,701

 
$
81,549

   NAMining
42,823

 
36,950

   Minerals Management
30,119

 
17,352

   Unallocated Items
790

 
665

   Eliminations
(1,443
)
 
(1,141
)
Total revenue
$
140,990

 
$
135,375

Operating profit (loss):
 
 
 
   Coal Mining
$
23,268

 
$
38,270

   NAMining
(696
)
 
1,918

   Minerals Management
25,721

 
14,331

   Unallocated Items
(9,729
)
 
(10,473
)
   Eliminations
256

 
(422
)
Total operating profit
$
38,820

 
$
43,624

   Interest expense
872

 
1,998

   Interest income
(3,616
)
 
(865
)
   Income from other unconsolidated affiliates
(1,300
)
 
(1,276
)
   Closed mine obligations
1,537

 
1,297

   (Gain) loss on equity securities
(1,545
)
 
316

   Other, net
(527
)
 
(9
)
Other (income) expense, net
(4,579
)
 
1,461

Income before income tax provision
43,399

 
42,163

Income tax provision
3,767

 
7,378

Net income
$
39,632

 
$
34,785

 
 
 
 
Effective income tax rate
8.7
%
 
17.5
%

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

Other (income) expense, net

North American Coal Corporation India Private Limited ("NACC India") was formed to provide technical business advisory services to the third-party owner of a coal mine in India. During 2014, NACC India's customer defaulted on its contractual payment obligations and as a result of this default, NACC India terminated its contract with the customer and began pursuing contractual remedies. During the third quarter of 2019, the Company received payment of $2.7 million from NACC India's customer, of which $1.4 million related to past invoices and has been reported on the line Other, net, and $1.3 million represented interest income and has been reported on the line Interest income.


32


Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)





Interest expense decreased $1.1 million due to lower average borrowings under NACoal's revolving credit facility during 2019 compared with 2018.

Interest income increased $2.8 million due to the interest income related to the NACC India customer payment and increased income earned on invested cash during 2019 compared with 2018.

(Gain) loss on equity securities had improved returns on invested assets of Bellaire's Mine Water Treatment Trust during 2019 compared with 2018. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Mine Water Treatment Trust.

Other, net, increased $0.5 million due to the $1.4 million payment from NACC India's customer for past invoices, partially offset by $0.9 million in settlement expense for the Combined Defined Benefit Plan. See Note 14 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's pension and postretirement expense.

Income Taxes

The Company’s effective income tax rate was 8.7% for the year ended December 31, 2019. The 2019 effective income tax rate included a net discrete tax benefit of $2.5 million primarily resulting from changes in prior year estimates and the effective settlement of certain discrete tax items from on-going examinations.

The Company’s effective income tax rate was 17.5% for the year ended December 31, 2018. The 2018 effective income tax rate included $1.2 million of discrete tax expense primarily related to an additional valuation allowance provided against deferred tax assets in India as the Company had previously determined that such deferred tax assets do not meet the more likely than not standard for realization.

Excluding discrete items, the effective income tax rate would have been approximately 14.5% and 14.7% for the years ended December 31, 2019 and 2018, respectively.

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


33


Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)





LIQUIDITY AND CAPITAL RESOURCES

Cash Flows
The following tables detail the change in cash flow for the years ended December 31:
 
2019
 
2018
 
Change
Operating activities:
 
 
 
 
 
Net income
$
39,632

 
$
34,785

 
$
4,847

Depreciation, depletion and amortization
16,240

 
14,683

 
1,557

Deferred income taxes
8,698

 
9,281

 
(583
)
Stock-based compensation
4,924

 
3,958

 
966

Gain on sale of assets
(206
)
 
(892
)
 
686

Other
(7,071
)
 
(7,612
)
 
541

Working capital changes
(9,433
)
 
419

 
(9,852
)
Net cash provided by operating activities
52,784

 
54,622

 
(1,838
)
 
 
 
 
 
 
Investing activities:
 
 
 
 
 
Expenditures for property, plant and equipment
(24,664
)
 
(20,930
)
 
(3,734
)
Proceeds from the sale of assets
4,572

 
1,454

 
3,118

Other
(170
)
 
1,089

 
(1,259
)
Net cash used for investing activities
(20,262
)
 
(18,387
)
 
(1,875
)
 
 
 
 
 
 
Cash flow before financing activities
$
32,522

 
$
36,235

 
$
(3,713
)

The $1.8 million decrease in net cash provided by operating activities was primarily the result of unfavorable working capital changes, partially offset by the increase in net income. Working capital changed unfavorably during 2019 primarily due to an increase in inventory at MLMC as a result of a decrease in customer requirements. A decrease in accounts receivable from affiliates during 2018, specifically attributable to payments from Hamilton Beach Brands Holding Company and Bisti Fuels Company, LLC, that did not reoccur in 2019, also contributed to the unfavorable change in working capital.

The increase in net cash used for investing activities was primarily attributable to an increase in expenditures for property, plant and equipment at MLMC and NAMining's operations in 2019 compared with 2018, partially offset by an increase in proceeds from the sale of assets in 2019.
 
2019
 
2018
 
Change
Financing activities:
 
 
 
 
 
Net additions (reductions) to long-term debt and revolving credit agreements
13,258

 
$
(46,729
)
 
$
59,987

Cash dividends paid
(5,132
)
 
(4,578
)
 
(554
)
Other
(3,013
)
 
(1,271
)
 
(1,742
)
Net cash provided by (used for financing) activities
$
5,113

 
$
(52,578
)
 
$
57,691


The change in net cash provided by (used for) financing activities was primarily due to increased borrowings during 2019 compared to repayments of borrowings during 2018.


34


Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)





Financing Activities
  
Financing arrangements are obtained and maintained at the subsidiary level. NACCO has not guaranteed any borrowings of NACoal. The borrowing agreements at NACoal allow for the payment to NACCO of dividends and advances under certain circumstances. Dividends (to the extent permitted by NACoal's borrowing agreement) and management fees are the primary sources of cash for NACCO and enable the Company to pay dividends to stockholders.

The Company believes funds available from cash on hand, the NACoal Facility and operating cash flows will provide sufficient liquidity to meet its operating needs and commitments arising during the next twelve months and until the expiration of the NACoal Facility.
NACoal has an unsecured revolving line of credit of up to $150.0 million (the “NACoal Facility”) that expires in August 2022. Borrowings outstanding under the NACoal Facility were $16.0 million at December 31, 2019. At December 31, 2019, the excess availability under the NACoal Facility was $132.6 million, which reflects a reduction for outstanding letters of credit of $1.4 million.

The NACoal Facility has performance-based pricing, which sets interest rates based upon NACoal achieving various levels of debt to EBITDA ratios, as defined in the NACoal Facility. Borrowings bear interest at a floating rate plus a margin based on the level of debt to EBITDA ratio achieved. The applicable margins, effective December 31, 2019, for base rate and LIBOR loans were 0.75% and 1.75%, respectively. The NACoal Facility has a commitment fee which is based upon achieving various levels of debt to EBITDA ratios. The commitment fee was 0.30% on the unused commitment at December 31, 2019. The weighted average interest rate applicable to the NACoal Facility at December 31, 2019 was 5.50% including the floating rate margin.

The NACoal Facility contains restrictive covenants, which require, among other things, NACoal to maintain a maximum debt to EBITDA ratio of 3.00 to 1.00 and an interest coverage ratio of not less than 4.00 to 1.00. The NACoal Facility provides the ability to make loans, dividends and advances to NACCO, with some restrictions based on maintaining a maximum debt to EBITDA ratio of 2.00 to 1.00, or if greater than 2.00 to 1.00, a Fixed Charge Coverage Ratio of 1.10 to 1.00, in conjunction with maintaining unused availability thresholds of borrowing capacity, as defined in the NACoal Facility, of $15.0 million. At December 31, 2019, NACoal was in compliance with all financial covenants in the NACoal Facility.

Capital Expenditures

Following is a table which summarizes actual and planned capital expenditures (in millions):
 
Planned
 
Actual
 
Actual
 
2020
 
2019
 
2018
NACCO
$
33.2

 
$
24.7

 
$
20.9


Planned expenditures for 2020 are expected to be approximately $33 million, primarily consisting of $24 million in the Coal Mining segment and $9 million in the NAMining segment. Capital expenditures are expected to be funded from internally generated funds and/or bank borrowings.

In the Coal Mining segment, elevated levels of expected capital expenditures through 2021 are primarily related to spending at MLMC as it develops a new mine area. In the NAMining segment, capital expenditures in 2020 are primarily for the acquisition, relocation and refurbishment of draglines.

35


Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)





Capital Structure

NACCO's consolidated capital structure is presented below:
 
December 31
 
 
 
2019
 
2018
 
Change
Cash and cash equivalents
$
122,892

 
$
85,257

 
$
37,635

Other net tangible assets 
174,465

 
156,703

 
17,762

Intangible assets, net
37,902

 
40,516

 
(2,614
)
Net assets
335,259

 
282,476

 
52,783

Total debt
(24,943
)
 
(11,021
)
 
(13,922
)
Closed mine obligations
(20,924
)
 
(20,751
)
 
(173
)
Total equity
$
289,392

 
$
250,704

 
$
38,688

Debt to total capitalization
8
%
 
4
%
 
4
%

The increase in net assets was primarily due to the increase in cash and cash equivalents. The increase in other net tangible assets also contributed to the change in net assets, mainly due to an increase in property, plant and equipment.
Contractual Obligations, Contingent Liabilities and Commitments
Following is a table which summarizes the contractual obligations of the Company as of December 31, 2019:
 
Payments Due by Period
Contractual Obligations
Total
 
2020
 
2021
 
2022
 
2023
 
2024
 
Thereafter
NACoal Facility
$
16,000

 
$
7,000

 
$

 
$
9,000

 
$

 
$

 
$

Interest payments on NACoal Facility
1,362

 
681

 
495

 
186

 

 

 

Other debt
10,317

 
567

 
567

 
567

 
567

 
567

 
7,482

Other interest
69

 
26

 
26

 
17

 

 

 

Deferred compensation
13,465

 
13,465

 

 

 

 

 

Finance lease obligations
657

 
567

 
37

 
37

 
16

 

 

Operating leases
19,193

 
2,193

 
2,149

 
2,175

 
1,685

 
1,661

 
9,330

Purchase and other obligations
43,737

 
43,737

 

 

 

 

 

Total contractual cash obligations
$
104,800

 
$
68,236

 
$
3,274

 
$
11,982

 
$
2,268

 
$
2,228

 
$
16,812

An event of default, as defined in the NACoal Facility and the Company’s lease agreements, could cause an acceleration of the payment schedule. No such event of default has occurred or is anticipated to occur.
NACoal’s variable interest payments are calculated based upon NACoal’s anticipated payment schedule and the December 31, 2019 base rate and applicable margins, as defined in the NACoal Facility. A 1/8% increase in the base rate would increase NACoal’s estimated total annual interest payments on the NACoal Facility by $0.2 million.
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)," which is codified in ASC 842, Leases (“ASC 842”) and supersedes current lease guidance in ASC 840. ASC 842 required a lessee to recognize a right-of-use asset and a corresponding lease liability for substantially all leases beginning January 1, 2019 for NACCO. See Note 10 to the Consolidated Financial Statements in this Form 10-K for further information on the Company's leases.
The purchase and other obligations are primarily for accounts payable, open purchase orders and accrued payroll and incentive compensation.
Pension and postretirement funding can vary significantly each year due to plan amendments, changes in the market value of plan assets, legislation and the Company’s decisions to contribute above the minimum regulatory funding requirements. As a

36


Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)





result, pension and postretirement funding has not been included in the table above. The Company does not expect to contribute to its pension plan in 2020. NACCO maintains one supplemental retirement plan that pays monthly benefits to participants directly out of corporate funds and expects to pay benefits of approximately $0.6 million in 2020 and approximately $0.5 million per year from 2021 through 2029. Benefit payments beyond that time cannot currently be estimated. All other pension benefit payments are made from assets of the pension plan. NACCO also expects to make payments related to its other postretirement plans of approximately $0.2 million per year from 2020 through 2029. Benefit payments beyond that time cannot currently be estimated.
Not included in the table above, the Company has a long-term liability of approximately $2.5 million for unrecognized tax benefits, including interest and penalties, as of December 31, 2019. At this time, the Company is unable to make a reasonable estimate of the timing of payments due to, among other factors, the uncertainty of the timing and outcome of its tax audits.
NACCO has asset retirement obligations that are not included in the table above due to the uncertainty of the timing of payments to settle this liability. See Note 7 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's asset retirement obligations.

NACoal is a party to certain guarantees related to Coyote Creek that are not included in the table above as the Company believes that the likelihood of NACoal’s future performance under the guarantees is remote, and no amounts related to these guarantees have been recorded. See Note 17 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's guarantees.

Off Balance Sheet Arrangements
The Company has not entered into any off balance sheet financing arrangements.
ENVIRONMENTAL MATTERS
The Company is affected by the regulations of numerous agencies, particularly the Federal Office of Surface Mining, the U.S. Environmental Protection Agency, the U.S. Army Corps of Engineers and associated state regulatory authorities. In addition, the Company closely monitors proposed legislation and regulation concerning SMCRA, CAA, ACE, CWA, RCRA, CERCLA and other regulatory actions.
Compliance with these increasingly stringent regulations could result in higher expenditures for both capital improvements and operating costs. The Company’s policies stress environmental responsibility and compliance with these regulations. Based on current information, management does not expect compliance with these regulations to have a material adverse effect on the Company’s financial condition or results of operations. See Item 1 in Part I of this Form 10-K for further discussion of these matters.


37


Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)





SEGMENT RESULTS

COAL MINING SEGMENT

FINANCIAL REVIEW
Tons of coal delivered by the Coal Mining segment were as follows for the years ended December 31 (in millions):
 
2019
 
2018
Unconsolidated mines
32.0

 
35.5

Consolidated mines
2.6

 
3.0

Total tons delivered
34.6

 
38.5

Total coal reserves were as follows at December 31:
 
2019 (1)
 
2018
 
(in billions of tons)
Unconsolidated mines
1.0

 
0.9

Consolidated mines
1.0

 
1.0

Total coal reserves
2.0

 
1.9

(1)Amount includes 0.1 million of coal reserves owned or controlled by customers. The Company conducts activities to extract these customer-owned and controlled reserves.
The results of operations for the Coal Mining segment were as follows for the years ended December 31:
 
2019
 
2018
Revenues
$
68,701

 
$
81,549

Cost of sales
65,430

 
70,112

Gross profit
3,271

 
11,437

Earnings of unconsolidated operations(a)
60,678

 
64,389

Selling, general and administrative expenses
38,246

 
34,798

Amortization of intangible assets
2,614

 
3,038

Gain on sale of assets
(179
)
 
(280
)
Operating profit
$
23,268

 
$
38,270

(a) See Note 17 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's unconsolidated subsidiaries, including summarized financial information.
2019 Compared with 2018

The following table identifies the components of change in revenues for 2019 compared with 2018:

 
Revenues
2018
$
81,549

Increase (decrease) from:
 
Consolidated operations
(9,859
)
MLMC contractual settlements in 2018
(2,989
)
2019
$
68,701



38


Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)





Revenues decreased 15.8% in 2019 compared with 2018 primarily due to a decrease in MLMC's tons delivered. MLMC delivers coal to the Red Hills Power Plant, which supplies electricity to TVA under a long-term Power Purchase Agreement. The decision of which power plants to dispatch is determined by TVA. The Red Hills power plant saw a decrease in the number of days TVA dispatched the plant in 2019 compared with 2018. As a result of this reduction in customer demand, tons delivered decreased in 2019 compared with 2018. MLMC's contractual settlements in 2018 related to resolution of its customer’s tonnage-related payment obligations and coal pricing adjustments.

The following table identifies the components of change in operating profit for 2019 compared with 2018:

 
Operating Profit
2018
$
38,270

Increase (decrease) from:
 
Revisions to Centennial's asset retirement obligation
(5,256
)
Earnings of unconsolidated operations
(3,711
)
Selling, general and administrative expenses
(3,448
)
MLMC contractual settlements in 2018
(2,989
)
Net gain on sale of assets
(101
)
Amortization of intangibles
424

Gross profit, excluding asset retirement obligation revisions
79

2019
$
23,268


Operating profit decreased $15.0 million in 2019 compared with 2018. The decrease was primarily the result of revisions to Centennial's asset retirement obligation, a decrease in earnings of unconsolidated operations and an increase in selling, general and administrative expenses, mainly due to higher employee-related and insurance costs.

The change in Centennial's asset retirement obligation is attributable to the absence of a $2.8 million favorable revision that occurred during 2018 and a $2.5 million unfavorable revision during 2019. See Note 7 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's asset retirement obligations.

The decrease in earnings of unconsolidated operations was primarily due to fewer coal tons delivered as a result of changes in customer demand, mainly related to the timing and duration of outages at certain customer facilities, partially offset by an increase in coal tons delivered at Bisti. Coal deliveries at Bisti were reduced during the prior year while the power plant's owners were installing additional environmental controls.

NORTH AMERICAN MINING ("NAMining") SEGMENT

FINANCIAL REVIEW
Tons of limestone delivered by the NAMining segment were as follows for the years ended December 31 (in millions):
 
2019
 
2018
Unconsolidated operations
8.3

 
7.0

Consolidated operations
36.4

 
39.0

Total tons delivered
44.7

 
46.0


39


Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)





The results of operations for the NAMining segment were as follows for the years ended December 31:
 
2019
 
2018
Revenues
$
42,823

 
$
36,950

Cost of sales
41,698

 
33,261

Gross profit
1,125

 
3,689

Earnings of unconsolidated operations(a)
3,205

 
605

Selling, general and administrative expenses
5,053

 
2,987

Gain on sale of assets
(27
)
 
(611
)
Operating profit (loss)
$
(696
)
 
$
1,918

(a) See Note 17 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's unconsolidated subsidiaries, including summarized financial information.
2019 Compared with 2018

Revenues

Despite the decrease in tons delivered at the consolidated operations, revenues increased 15.9% in 2019 compared with 2018, primarily due to increased deliveries under fixed-price contract mining agreements.

The following table identifies the components of change in operating profit (loss) for 2019 compared with 2018.
 
Operating Profit (Loss)
2018
$
1,918

Increase (decrease) from:
 
Gross profit
(2,564
)
Selling, general and administrative expenses
(2,066
)
Net gain on sale of assets
(584
)
Earnings of unconsolidated operations
2,600

2019
$
(696
)

NAMining reported an operating loss of $0.7 million in 2019 compared with operating profit of $1.9 million in 2018. The change is primarily due to a decrease in gross profit, mainly due to higher labor, equipment repairs and supplies expenses. An increase in selling, general and administrative expenses, which includes higher employee-related and business development costs, also contributed to the change in operating profit (loss). These decreases were partially offset by an improvement in earnings of unconsolidated operations, which benefited from increased customer requirements and increased deliveries under fixed-price contract mining agreements.


40


Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)





MINERALS MANAGEMENT SEGMENT
FINANCIAL REVIEW
The results of operations for the Minerals Management segment were as follows for the years ended December 31:
 
2019
 
2018
Revenues
$
30,119

 
$
17,352

Cost of sales
3,465

 
2,122

Gross profit
26,654

 
15,230

Selling, general and administrative expenses
933

 
900

Gain on sale of assets

 
(1
)
Operating profit
$
25,721

 
$
14,331

2019 Compared with 2018

Revenues and Operating Profit

Revenues and operating profit increased in 2019 compared with 2018, primarily due to an increase in the number of wells operated by third parties to extract natural gas from the Company's mineral reserves in Ohio. The number of producing wells increased as operators increased activity on Minerals Management's reserves and additional pipeline, gas compression, and other transportation infrastructure came online in southeast Ohio.

UNALLOCATED ITEMS AND ELIMINATIONS

FINANCIAL REVIEW
Unallocated Items and Eliminations were as follows for the years ended December 31:
 
2019
 
2018
Operating loss
$
(9,473
)
 
$
(10,895
)
2019 Compared with 2018

The $1.4 million decrease in operating loss in 2019 compared with 2018 was primarily due to lower professional fees as 2018 included fees incurred for arbitration with a former customer.

NACCO Industries, Inc. Outlook

Coal Mining Outlook - 2020
In 2020, the Company expects coal deliveries to increase modestly compared with 2019. The anticipated increase in coal deliveries is a result of an expected increase in customer demand, as the Company's customers are generally forecasting a reduction in power plant outage days and an increase in the number of days dispatched in 2020.

Coal Mining operating profit is expected to increase in 2020 over 2019. This anticipated increase is primarily the result of an expected increase in gross profit at MLMC, primarily in the first half of the year, and the absence of the $2.0 million unfavorable adjustment to mine reclamation liabilities at Centennial in the fourth quarter of 2019. A modest improvement in earnings at the unconsolidated Coal Mining operations is also expected to contribute to the increase in operating profit, but these improvements are expected to be partly offset by an increase in operating expenses primarily from anticipated higher professional fees and IT expenses.

The increase in gross profit at MLMC is expected to be driven by higher customer demand due to an anticipated increase in the number of days the customer's power plant is expected to be dispatched in 2020. If customer demand at MLMC decreases

41


Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)





from expected levels, it could unfavorably affect the Company's 2020 earnings, as reduced customer demand affected earnings in 2019.

Capital expenditures are expected to be approximately $24 million in 2020. The Company expects high levels of capital expenditures in 2020 and 2021 primarily related to anticipated spending at MLMC as it develops a new mine area. These capital expenditures will result in an increase in depreciation that will unfavorably affect operating profit in future periods.

During the first quarter of 2020, Great River Energy, Falkirk's customer, announced that it is evaluating the economics of the Coal Creek Station power plant.  The Company has a management fee mining contract to supply coal to this plant that expires in 2045. Any decision by Great River Energy to reduce operations or prematurely close this power plant would have a material adverse effect on the Company’s results of operations. The mining contract specifies that Great River Energy is responsible for all mine closure costs.

NAMining Outlook
In 2020, NAMining expects limestone deliveries to increase and full year operating results to improve significantly over 2019. Operating profit is expected to benefit from earnings associated with new limestone mining contracts. The improvement in operating profit is expected to be partly offset by an increase in operating expenses due to higher employee-related costs associated with new mining operations.

Capital expenditures are expected to be $9 million in 2020, primarily for the acquisition, relocation and refurbishment of draglines.

In 2019, NAMining, through a new subsidiary, Sawtooth Mining, LLC, entered into a mining agreement to serve as the exclusive contract miner for the Thacker Pass lithium project, owned by Lithium Nevada, Corp., in northern Nevada. Sawtooth Mining will provide comprehensive mining services, with responsibility for all aspects of the lithium mine, similar to our typical scope of work in the Coal Mining segment. The mining agreement provides that Lithium Nevada will reimburse Sawtooth for its operating and mine reclamation costs, and pay Sawtooth Mining a management fee per metric ton of lithium delivered during the 20-year contract term. Lithium Nevada is in the process of securing permits and currently expects to commence construction in 2021 and production of lithium products in 2023.

Minerals Management Outlook
The Minerals Management segment derives income from royalty-based leases under which lessees make payments to the Company based on their sale of natural gas and, to a lesser extent, oil, natural gas liquids and coal, extracted primarily by third parties. The Company experienced a significant increase in royalty income in 2019 compared with 2018, primarily due to a significant increase in the number of gas wells operated by third parties to extract natural gas from the Company's Ohio Utica shale mineral reserves. Because new wells have high initial production rates and follow a natural decline before settling into relatively stable, long-term production, royalty income in 2020 is expected to decrease and be substantially lower than 2019 levels. This decrease is expected to occur primarily in the first half of the year, particularly in the first quarter, as comparisons are made to historically high revenue levels in the first half of 2019 associated with increased production levels in the early stages of production from new wells. The reduction in royalty income is based on natural gas price expectations, fewer expected new wells and the natural production decline that occurs early in the life of a well. Decline rates can vary due to factors like well depth, well length, 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 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. 

Consolidated Outlook
Overall, in 2020, NACCO expects a modest decrease in operating profit compared with 2019 mainly due to the substantial decrease in Minerals Management's results and an increase in consolidated operating expenses, partly offset by expected improvements in earnings at both the Coal Mining and NAMining segments.


42


Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)





Consolidated net income in 2020 is expected to decrease compared with 2019, predominantly in the first half of the year, mainly as a result of the anticipated reduction in Minerals Management operating profit, as well as the absence of $2.7 million pre-tax received in 2019 associated with a prior India venture and the absence of a $2.5 million tax benefit recognized in the fourth quarter of 2019. The 2020 full-year effective income tax rate is expected to be between 10% and 12%, based on the anticipated mix of earnings and excluding discrete items.

In 2020, cash flow before financing activities is expected to decrease significantly from 2019 levels due to a significant increase in capital expenditures and payment of deferred compensation and other payroll liabilities. Consolidated capital expenditures are expected to be approximately $33 million in 2020 compared with $24.7 million in 2019.

One of the Company’s core strategies is to pursue activities which can strengthen the resiliency of its existing coal mining operations. The Company works to drive down coal production costs and maximize efficiencies and operating capacity at mine locations to help customers with management fee contracts be more competitive. This benefits both customers and the Company's Coal Mining segment, as fuel cost is the major driver for power plant dispatch. Increased power plant dispatch drives increased demand for coal by the Coal Mining segment's customers, just as lower dispatch reduces demand.

The Company continues to evaluate opportunities to expand its core coal mining business, however opportunities are likely to be very limited. Low natural gas prices and growth in renewable energy sources, such as wind and solar, could continue to unfavorably affect the amount of electricity dispatched from coal-fired power plants. The political and regulatory environment is not generally receptive to development of new coal-fired power generation projects which would create opportunities to build and operate new coal mines. However, the Company does continue to seek out and pursue opportunities where it can apply its management fee business model to replace legacy operators of existing surface coal mining operations in the United States. Outright acquisitions of existing coal mines or mining companies with exposure to fluctuating coal commodity markets, or structures that would create significant leverage, are outside the Company’s area of focus.

The Company is focused on building a strong portfolio of affiliated businesses for diversified growth. It continues to expand the scope of its business development activities related to growing NAMining beyond aggregates, by providing additional mining services where the Company’s core mining skills can add value to customers of a broad range of minerals and materials, including by providing comprehensive mining services, and expanding the range of contract mining services. The Company is also considering the acquisition of additional mineral interests or similar investments in the energy industry as part of the growth of Minerals Management, with an initial focus on smaller, diversifying acquisitions with near-term cash flow yields. The Company has recently formed Mitigation Resources of North America® to create and sell stream and wetland mitigation credits and provide services to those engaged in permittee-responsible mitigation. This new business has achieved several early successes and is positioned for additional growth.

The Company is leveraging its core mining skills to develop a strong and diverse portfolio of service-based businesses operating in the mining and natural resources industries. The Company is also committed to maintaining a conservative capital structure while it grows and diversifies without unnecessary risk. Ultimately, diversified strategic growth is the key to increasing free cash flow available to continue to re-invest in and expand the businesses. The Company also continues to maintain the highest levels of customer service and operational excellence, with an unwavering focus on safety and environmental stewardship.

RECENTLY ISSUED ACCOUNTING STANDARDS

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


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Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NACCO INDUSTRIES, INC. AND SUBSIDIARIES
(Tabular Amounts in Thousands, Except Per Share and Percentage Data)





FORWARD-LOOKING STATEMENTS
The statements contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere throughout this Annual Report on Form 10-K that are not historical facts are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are made subject to certain risks and uncertainties, which could cause actual results to differ materially from those presented. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. The Company undertakes no obligation to publicly revise these forward-looking statements to reflect events or circumstances that arise after the date hereof. Among the factors that could cause plans, actions and results to differ materially from current expectations are, without limitation: (1) changes to or termination of a long-term mining contract, or a customer default under a contract, including any decision by Great River Energy to reduce operations or prematurely close the Coal Creek Station power plant, (2) changes in coal consumption patterns of U.S. electric power generators or the power industry that would affect demand for the Company's mineral reserves, (3) changes in tax laws or regulatory requirements, including changes in mining or power plant emission regulations and health, safety or environmental legislation, (4) changes in costs related to geological and geotechnical conditions, repairs and maintenance, new equipment and replacement parts, fuel or other similar items, (5) regulatory actions, changes in mining permit requirements or delays in obtaining mining permits that could affect deliveries to customers, (6) weather conditions, extended power plant outages, liquidity events or other events that would change the level of customers' coal or aggregates requirements, (7) weather or equipment problems that could affect deliveries to customers, (8) failure or delays by the Company's lessees in achieving expected production of natural gas and other hydrocarbons; the availability and cost of transportation and processing services in the areas where the Company's oil and gas reserves are located; federal and state legislative and regulatory initiatives relating to hydraulic fracturing; and the ability of lessees to obtain capital or financing needed for well development operations, (9) changes in the costs to reclaim mining areas, (10) costs to pursue and develop new mining and value-added service opportunities, (11) delays or reductions in coal or aggregates deliveries, (12) changes in the prices of hydrocarbons, particularly diesel fuel, natural gas and oil, (13) increased competition, including consolidation within the coal and aggregates industries, and (14) disruption from natural or human causes, including severe weather, accidents, fires, earthquakes, terrorist acts and epidemic or pandemic diseases, such as the coronavirus, any of which could result in suspension of operations or harm to people or the environment.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

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

There were no disagreements with accountants on accounting and financial disclosure for the two-year period ended December 31, 2019 that require disclosure pursuant to this Item 9.

Item 9A. CONTROLS AND PROCEDURES
Evaluation of disclosure controls and procedures: An evaluation was carried out under the supervision and with the participation of the Company's management, including the principal executive officer and the principal financial officer, of the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, these officers have concluded that the Company's disclosure controls and procedures are effective.
Management's report on internal control over financial reporting: Management is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on this evaluation under the framework, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2019. The Company's effectiveness of internal control over financial reporting as of December 31, 2019 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in its report, which is included in Item 15 of this Form 10-K and incorporated herein by reference.
Changes in internal control: There have been no changes in the Company's internal control over financial reporting, that occurred during the fourth quarter of 2019, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

Item 9B. OTHER INFORMATION
None.

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PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information with respect to Directors of the Company will be set forth in the 2020 Proxy Statement under the subheadings “Part III — Proposals To Be Voted On At The 2020 Annual Meeting — Proposal 1 — Election of Directors,” which information is incorporated herein by reference.
Information with respect to the audit review committee and the audit review committee financial expert will be set forth in the 2020 Proxy Statement under the subheading “Part I — Corporate Governance Information — Directors' Meetings and Committees,” which information is incorporated herein by reference.
Information with respect to compliance with Section 16(a) of the Securities Exchange Act of 1934 by the Company's Directors, executive officers and holders of more than ten percent of the Company's equity securities will be set forth in the 2020 Proxy Statement under the subheading “Part IV — Other Important Information — Section 16(a) Beneficial Ownership Reporting Compliance,” which information is incorporated herein by reference.
The Company has adopted a code of business conduct and ethics applicable to all Company personnel, including the principal executive officer, principal financial officer, principal accounting officer or controller, or other persons performing similar functions. The code of business conduct and ethics, entitled the “Code of Corporate Conduct,” is posted on the Company's website at www.nacco.com under “Corporate Governance.” If the Company makes any amendments to or grants any waivers from the code of business conduct and ethics which are required to be be disclosed pursuant to the Securities and Exchange Act of 1934, the Company will make such disclosure on the NACCO website.

Item 11. EXECUTIVE COMPENSATION
Information with respect to executive compensation will be set forth in the 2020 Proxy Statement under the headings “Part II — Executive Compensation Information” and “Part III — Proposals To Be Voted On At The 2020 Annual Meeting — Proposal 1 — Election of Directors,” which information is incorporated herein by reference.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information with respect to security ownership of certain beneficial owners and management will be set forth in the 2020 Proxy Statement under the subheading “Part IV — Other Important Information — Beneficial Ownership of Class A Common and Class B Common,” which information is incorporated herein by reference.
Information with respect to compensation plans (including individual compensation arrangements) under which equity securities are authorized for issuance will be set forth in the 2020 Proxy Statement under the subheading “Part IV — Other Important Information — Equity Compensation Plan Information," which information is incorporated herein by reference.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information with respect to certain relationships and related transactions will be set forth in the 2020 Proxy Statement under the subheadings “Part I — Corporate Governance Information — Review and Approval of Related-Person Transactions,” which information is incorporated herein by reference.

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information with respect to principal accountant fees and services will be set forth in the 2020 Proxy Statement under the heading “Part III — Proposals To Be Voted On At The 2020 Annual Meeting — Proposal 3 — Ratification of the Appointment of Company's Independent Registered Public Accounting Firm,” which information is incorporated herein by reference.


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PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) (1) and (2) The response to Item 15(a)(1) and (2) is set forth beginning at page F-1 of this Form 10-K.
(b) Financial Statement Schedules — The response to Item 15(c) is set forth beginning at page F-34 of this Form 10-K.
(c) Exhibits required by Item 601 of Regulation S-K
Exhibit Number
 
Exhibit Description
(3) Articles of Incorporation and By-laws.
3.1(i) 
 
Restated Certificate of Incorporation of the Company is incorporated herein by reference to Exhibit 3(i) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File Number 1-9172.
3.1(ii) 
 
 
 
 
(4) Instruments defining the rights of security holders, including indentures.
4.1
 
The Company by this filing agrees, upon request, to file with the Securities and Exchange Commission the instruments defining the rights of holders of long-term debt of the Company and its subsidiaries where the total amount of securities authorized thereunder does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis.
4.2
 
The Mortgage and Security Agreement, dated April 8, 1976, between The Falkirk Mining Company (as Mortgagor) and Cooperative Power Association and United Power Association (collectively, as Mortgagee) is incorporated herein by reference to Exhibit 4(ii) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File Number 1-9172.
4.3
 
Amendment No. 1 to the Mortgage and Security Agreement, dated as of December 15, 1993, between Falkirk Mining Company (as Mortgagor) and Cooperative Power Association and United Power Association (collectively, as Mortgagee) is incorporated herein by reference to Exhibit 4(iii) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, Commission File Number 1-9172.
4.4
 
4.5
 
4.6**
 









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