What changed in this filing

/stocks — the workspaceLOADING

Item 1. Business

2021-02-23 compared with 2020-02-20 · 176 added, 188 removed, 593 unchanged (38% of the section changed)

2 unchanged sentences

We believe that ARLP's diverse and rich resource base will allow ARLP to continue to create long-term value for unitholders.

We are currently the second largest coal producer in the eastern United States with seven underground mining complexes in Illinois, Indiana, Kentucky, Maryland and West Virginia as well as a coal-loading terminal in Indiana.

We are currently the second-largest coal producer in the eastern United States with seven underground mining complexes in Illinois, Indiana, Kentucky, Maryland, Pennsylvania, and West Virginia as well as a coal-loading terminal in Indiana on the Ohio River.

We manage and report our coal operations primarily under two regions, Illinois Basin and Appalachia.

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Reserve additions and the associated cash flows are expected to increase from the development of our existing mineral interests and through acquisitions of additional mineral interests.

In addition, we provide terminal services for the transloading of coal, and develop and market industrial and mining technology products and services.

In addition, we develop and market industrial and mining technology products and services.

ARLP, a Delaware limited partnership, completed its initial public offering on August 19, 1999, and is listed on the NASDAQ Global Select Market under the ticker symbol "ARLP."

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AllDale Acquisition provides ARLP with diversified exposure to industry leading operators and is consistent with our general business strategy to pursue accretive acquisitions.

Kodiak Redemption

On January 26, 2019, Kodiak Gas Services, LLC ("Kodiak") provided notification that it intended to redeem our preferred interest for $135.0 million, which is inclusive of an early redemption premium.

On February 8, 2019, we received the cash proceeds of the redemption.

Wing Acquisition

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Coal is used primarily for the generation of electric power and production of steel but is also used for chemical, food, and cement processing.

We produce bituminous coal from our underground mines that is sold to customers principally for electric power generation (thermal) and for production of steel (metallurgical).

We produce bituminous coal from our underground mines that is sold to customers principally for electric power generation (thermal) and for the production of steel (metallurgical).

We have established long-term relationships with customers through exemplary and consistent performance while operating our mines with an industry-leading safety record.

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In 2020, approximately 94.2% of our tons sold were purchased by United States electric utilities and 3.3% were sold into the international markets through brokered transactions.

The balance of our tons sold were to third-party resellers and industrial consumers.

The balance of our tons sold was to third-party resellers and industrial consumers.

For tons sold to United States electric utilities, 100% were sold to utility plants with installed pollution control devices.

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The following map shows the location of our coal mining operations:

Designated reserves noted on the map and reserves associated with our mining complexes may be owned or held by Alliance Resource Properties, our land holding company, with intercompany leases to our mining complexes.

Illinois Basin Operations:

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Gibson South Mine

Gibson North Mine (Idled)

Mining Access:

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Slope & Shaft

Mining Access:

Slope & Shaft

Mining Method:

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Mining Method:

Mining Access:

Slope & Shaft

& Continuous Miner

Mining Method:

& Continuous Miner

Medium/High-Sulfur

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Medium/High-Sulfur

Low/Medium-Sulfur

Transportation:

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Barge & Railroad

Low/Medium-Sulfur

Transportation:

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MC MINING COMPLEX

HAMILTON COMPLEX

TRANSFER TERMINAL

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Slope & Shaft

HAMILTON COMPLEX

Hamilton Mine

Rail or Truck to Ohio River Barge

Excel Mine No.

5 (in development)

Mining Method:

Hamilton Mine

Transloading Facility

& Continuous Miner

Mining Access:

Slope & Shaft

& Continuous Miner

Mining Access:

Slope & Shaft

HENDERSON/UNION

Mining Method:

HENDERSON/UNION

Transportation:

Barge & Railroad

Mining Method:

& Continuous Miner

1 unchanged sentence

Medium/High-Sulfur

Mining Access:

Slope & Shaft

Transportation:

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Barge, Railroad

Mining Access:

Slope & Shaft

Mining Method:

1 unchanged sentence

Medium/High-Sulfur

Transportation:

Barge & Truck

METTIKI COMPLEX

RIVER VIEW COMPLEX

Transportation:

Barge & Truck

Mountain View Mine

River View Mine

DOTIKI COMPLEX

Dotiki Mine (closed)

DOTIKI RESERVES

Mining Access:

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Barge, Railroad

We lease most of our coal reserves and generally have the right to maintain leases in force until the exhaustion of mineable and merchantable coal located within the leased premises or a larger coal reserve area.

These leases provide for royalties to be paid to the lessors at a fixed amount per ton or as a percentage of the sales price.

Many leases require payment of minimum royalties, payable either at the time of the execution of the lease or in periodic installments, even if

no mining activities have begun.

We lease most of our coal reserves from private parties and generally have the right to maintain leases in force until the exhaustion of mineable and merchantable coal located within the leased premises or a larger coal reserve area.

leases provide for royalties to be paid to the lessors at a fixed amount per ton or as a percentage of the sales price.

Many leases require payment of minimum royalties, payable either at the time of the execution of the lease or in periodic installments, even if no mining activities have begun.

These minimum royalties are normally credited against the production royalties owed to a lessor once coal production has commenced.

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The Gibson South mine's preparation plant has throughput capacity of 1,800 tons of raw coal per hour.

Production from the Gibson South mine is shipped by truck on United States and state highways or transported by rail on the CSX Transportation, Inc.

Production from the Gibson South mine is shipped by truck or transported by rail on the CSX Transportation, Inc.

("CSX") and Norfolk Southern Railway Company ("NS") railroads from the Gibson North rail loadout facility directly to customers or to various transloading facilities, including our Mt.

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Production from the mine began in April 2014.

Gibson County Coal also operates the Gibson North mine, an underground mine also located near the city of Princeton in Gibson County, Indiana.

The Gibson North mine began production in November 2000 and utilizes continuous mining units employing room-and-pillar mining techniques to produce low/medium-sulfur coal.

Gibson County Coal also operated the Gibson North mine, an underground mine also located near the city of Princeton in Gibson County, Indiana.

The Gibson North mine began production in November 2000 and utilized continuous mining units employing room-and-pillar mining techniques to produce low/medium-sulfur coal.

The Gibson North mine was idled in December 2015 in response to market conditions but resumed production in May 2018.

In November 2019, the Gibson North mine was again idled in response to market conditions.

The Gibson North mine's preparation plant has throughput capacity of 700 tons of raw coal per hour.

Production from the Gibson North mine is shipped by truck on United States and state highways or transported by rail on the CSX and NS railroads directly to customers or to various transloading facilities for barge delivery.

In November 2019, the Gibson North mine was again idled in response to market conditions and in May 2020, the Gibson North mine was reclaimed and sealed.

Hamilton Complex.

Our subsidiary, Hamilton County Coal, LLC ("Hamilton"), operates the Hamilton mine, located near the city of McLeansboro in Hamilton County, Illinois.

The Hamilton mine is an underground longwall mining operation producing medium/high-sulfur coal from the Herrin No.

The Hamilton mine is an underground longwall mining operation producing medium/high-sulfur coal.

Initial development production from the continuous miner units began in 2013, longwall mining began in October 2014 and we acquired complete ownership and control in 2015.

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Our subsidiary, River View Coal, LLC ("River View"), operates the River View mine, which is located in Union County, Kentucky and is currently the largest room-and-pillar coal mine in the United States.

The River View mine began production in 2009, and utilizes continuous mining units to produce medium/high-sulfur coal.

The River View mine began (multi-seam) production in 2009 and utilizes continuous mining units to produce medium/high-sulfur coal.

River View's preparation plant has throughput capacity of 2,700 tons of raw coal per hour.

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Warrior's production is shipped via the CSX and Paducah & Louisville Railway, Inc.

("PAL") railroads and by truck on United States and state highways directly to customers or potentially to various transloading facilities, including our Mt.

("PAL") railroads and by truck directly to customers or potentially to various transloading facilities, including our Mt.

Vernon transloading facility, for barge deliveries.

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The terminal has a capacity of 8.0 million tons per year with existing ground storage of approximately 200,000 tons.

During 2019, the terminal loaded approximately 3.9 million tons for customers of Gibson County Coal and Hamilton.

During 2020, the terminal loaded approximately 425,000 tons for customers of Gibson County Coal and Hamilton.

Alliance Resource Properties .

Alliance Resource Properties, LLC ("Alliance Resource Properties") and its subsidiaries own or control coal reserves that it leases to certain of our subsidiaries that operate our mining complexes.

In December 2014 and February 2015, WKY CoalPlay, LLC or its subsidiaries ("WKY CoalPlay"), which are related parties, entered into coal lease agreements with us regarding coal reserves located in Henderson and Union Counties, Kentucky

("Henderson/Union Reserves") and Webster County, Kentucky.

Alliance Resource Properties, LLC and collectively with its subsidiaries ("Alliance Resource Properties") own or control coal reserves that they lease to certain of our subsidiaries that operate our mining complexes, including Gibson South, Hamilton, River View and Warrior.

In December 2014 and February 2015, WKY CoalPlay, LLC or its subsidiaries ("WKY CoalPlay"), which are related parties, entered into coal lease agreements with

us regarding coal reserves located in Henderson and Union Counties, Kentucky ("Henderson/Union Reserves") and Webster County, Kentucky.

For more information about the WKY CoalPlay transactions, please read "Item 8.

2 unchanged sentences

Our subsidiary, Webster County Coal, LLC ("Webster County Coal"), operated Dotiki, an underground mining complex located near the city of Providence in Webster County, Kentucky.

The complex was opened in 1966, and we purchased the mine in 1971 and operated it until it ceased production in August 2019.

The complex opened in 1966, and we purchased the mine in 1971 and operated it until it ceased production in August 2019.

For information regarding Dotiki's remaining coal reserves, please read "Item 2.

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Our subsidiary, Hopkins County Coal, LLC ("Hopkins County Coal") operated the Elk Creek underground mine until it ceased production in April 2016.

We have begun performing reclamation activities at the complex.

For information regarding Hopkins' remaining coal reserves, please read "Item 2.

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Substantially all of the coal produced at MC Mining in 2020 met or exceeded the compliance requirements of Phase II of the Federal Clean Air Act ("CAA") (see "—Environmental, Health and Safety Regulations— Air Emissions "

Coal produced from the mine is shipped via the CSX railroad directly to customers or to various transloading facilities on the Ohio River for barge deliveries, or by truck via United States and state highways directly to customers or to various docks on the Big Sandy River for barge deliveries.

MC Mining's Excel Mine No.

4 is anticipated to deplete its reserves in 2020.

Our subsidiary, Excel, has completed most development activity for MC Mining's Excel Mine No.

5 and currently anticipates transitioning employees and equipment to the new mine by mid-2020.

Coal produced from the mine is shipped via the CSX railroad directly to customers or to various transloading facilities on the Ohio River for barge deliveries, or by truck directly to customers or to various docks on the Big Sandy River for barge deliveries.

Our subsidiary, Excel, completed development activity for MC Mining's Excel Mine No.

5 in May 2020 and transitioned its employees and equipment to the new mine in July 2020.

MC Mining controls the estimated 15 million tons of coal reserves assigned to the Excel Mine No.

5 and Excel will conduct all mining operations.

The underground operation will utilize continuous mining units employing room-and-pillar mining techniques to produce low-sulfur coal with an expected annual production capacity of 1.3 million tons.

MC Mining plans to utilize its existing underground mining equipment and preparation plant to produce and process coal from the Excel Mine No.

5 and expects to ship coal produced from the mine to various transloading facilities on the Ohio River and the Big Sandy River for barge deliveries or directly to customers via the CSX railroad and by truck.

We expect the development plan for the new Excel Mine No.

5 will provide a seamless transition from the current MC Mining operation.

The underground operation utilizes continuous mining units employing room-and-pillar mining techniques to produce low-sulfur coal with an expected annual production capacity of 1.3 million tons.

MC Mining utilizes its existing underground mining equipment and preparation plant to produce and process coal from the Excel Mine No.

5 and ships coal produced from the mine to various transloading facilities on the Ohio River and the Big Sandy River for barge deliveries or directly to customers via the CSX railroad and by truck.

The development plan for the new Excel Mine No.

5 provided a seamless transition from the current MC Mining operation.

Mettiki Complex.

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These arrangements are mutually beneficial to our customers and us in that they provide greater predictability of sales volumes and sales prices.

Although many utility customers have appeared to favor a shorter-term contracting strategy, in 2019 approximately 78.5% and 78.3% of our sales tonnage and total coal sales, respectively, were sold under long-term contracts with committed term expirations ranging from 2020 to 2024.

As of February 14, 2020, our nominal commitment under contract was approximately 29.3 million tons in 2020, 18.4 million tons in 2021 and 6.7 million tons in 2022.

The commitment of coal under contract is an approximate number because a limited number of our contracts contain provisions that could cause the nominal commitment to increase or decrease;

however, the overall variance to total committed sales is minimal.

Although some utility customers have appeared to favor a shorter-term contracting strategy, in 2020 approximately 93.0% and 92.8% of our sales tonnage and total coal sales, respectively, were sold under long-term contracts with committed term expirations ranging from 2020 to 2025.

As of February 1, 2021, our nominal commitment under contract was approximately 24.1 million tons in 2021.

The contractual time commitments for customers to nominate future purchase volumes under these contracts are typically sufficient to allow us to balance our sales commitments with prospective production capacity.

In addition, the nominal commitment can otherwise change because of reopener provisions contained in certain of these long-term contracts.

The provisions of long-term contracts are the results of both bidding procedures and extensive negotiations with each customer.

As a result, the provisions of these contracts vary significantly in many respects, including, among other factors, price adjustment features, price and contract reopener terms, permitted sources of supply, force majeure provisions, and coal qualities and quantities.

A portion of our long-term contracts are subject to price adjustment provisions, which periodically permit an increase or decrease in the contract price, typically to reflect changes in specified indices or changes in production costs resulting from regulatory changes, or both.

A portion of our long-term contracts is subject to price adjustment provisions, which periodically permit an increase or decrease in the contract price, typically to reflect changes in specified indices or changes in production costs resulting from regulatory changes, or both.

These provisions, however, may not assure that the contract price will reflect every change in production or other costs.

Failure of the parties to agree on a price pursuant to an adjustment or a reopener provision can, in some instances, lead to early termination of a contract.

Failure of the parties to agree on a price pursuant to an adjustment or a reopener provision can, in some instances, lead to the early termination of a contract.

Some of the long-term contracts also permit the contract to be reopened for renegotiation of terms and conditions other than pricing terms, and where a mutually acceptable agreement on terms and conditions cannot be concluded, either party may have the option to terminate the contract.

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Depending on the language of the contract, some contracts may terminate upon an event of force majeure that extends for a certain period.

The international coal market has been a substantial part of our business with indirect sales to end users in Europe, Africa, Asia, North America and South America.

Our sales into the international coal market are considered exports and are made through brokered transactions.

The international coal market has been a substantial part of our business with indirect sales to end-users in Europe, Africa, Asia, North America, and South America, although the share of our export sales fell significantly in 2020 due to reduced demand in the international coal market.

Our sales into the international coal market are considered exports and

are made through brokered transactions.

During the years ended December 31, 2020, 2019, and 2018, export tons represented approximately 3.3%, 17.9%, and 27.8% of tons sold, respectively.

2 unchanged sentences

Reliance on Major Customers

During 2019, we derived more than 10.0% of our total revenues from each of two customers, Louisville Gas and Electric Company and FirstEnergy Corp.

We did not derive 10.0% or more of our total revenues from any other individual customer during 2019.

For more information about these two customers, please read "Item 8.

In 2020, our key customers were American Electric Power, Louisville Gas and Electric Company, and Tennessee Valley Authority.

We generally define key customers as those from which we derive 10% or more of our total revenues during 2020.

For more information about these customers, please read "Item 8.

Financial Statement and Supplemental Data—Note 23 – Concentration of Credit Risk and Major Customers."

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We are currently the second-largest coal producer in the eastern United States.

Our principal competitors include CONSOL Energy, Inc., Contura Energy, Inc., Foresight Energy LP, Murray Energy, Inc., and Peabody Energy Corporation.

While a number of our competitors have been involved in reorganization in bankruptcy, these events have not resulted in a material diminution in available coal supply and there remains significant competition for ongoing coal sales.

Our principal competitors include American Consolidated Natural Resources Inc., CONSOL Energy, Inc., Alpha Metallurgical Resources, Inc., Foresight Energy LP, and Peabody Energy Corporation.

We also compete directly with a number of smaller producers in the Illinois Basin and Appalachian regions.

In addition, we compete with companies that produce coal from one or more foreign countries.

We export a significant portion of our coal into the international coal markets and historically the prices we obtain for our export coal have been influenced by a number of factors, such as global economic conditions, weather patterns, and global supply and demand, among others.

We seek to export a portion of our coal into the international coal markets and historically the prices we obtain for our export coal have been influenced by a number of factors, such as global economic conditions, weather patterns, and global supply and demand, among others.

Potential changes to international trade agreements, trade concessions, or other political and economic arrangements may benefit coal producers operating in countries other than the United States.

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As a consequence, the availability and cost of transportation constitute important factors in the marketability of coal.

We believe our mines are located in favorable geographic locations that minimize transportation costs for our customers, and in many cases we are able to accommodate multiple transportation options.

We believe our mines are

located in favorable geographic locations that minimize transportation costs for our customers, and in many cases, we are able to accommodate multiple transportation options.

Our customers typically negotiate and pay the transportation costs from the mining complex to the destination, which is the standard practice in the industry.

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With respect to our export volumes from the United States to other countries, we generally sell coal to our customers at an export terminal in the United States and we are responsible for the cost of transporting coal to the export terminals.

Our export customers generally negotiate and pay for the ocean vessel transportation.

Our export customers generally negotiate and pay for ocean vessel transportation.

Mineral Interest Activities

Our mineral interest business includes all activities related to the oil & gas mineral interests held by AR Midland and AllDale I & II and includes Alliance Minerals, LLC's ("Alliance Minerals") equity interests in both AllDale III and Cavalier Minerals.

Our mineral interest business includes all activities related to the oil & gas mineral interests held by AR Midland and AllDale I & II and includes Alliance Minerals' equity interests in both AllDale III and Cavalier Minerals.

AR Midland acquired its mineral interests in the Wing Acquisition.

Our mineral interests are primarily located in three basins, which are also our areas of focus for future development by operators.

Our mineral interests are primarily located on private lands in three basins, which are also our areas of focus for future development by operators.

These include the Permian (Delaware and Midland), Anadarko (SCOOP/STACK), and Williston (Bakken) Basins.

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Unlike owners of working interests in oil & gas properties, we are not obligated to fund drilling and completion costs or plugging and abandonment costs associated with oil & gas production.

The following chart summarizes production of our mineral interests for the year ended December 31, 2019:

The following chart summarizes the production of our mineral interests for the year ended December 31, 2020, and 2019:

Natural gas (MMcf)

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In 2014, ARLP began to actively invest in oil & gas mineral interests in some of the nation's premier oil-rich basins.

Throughout 2019, ARLP has transitioned from a passive investor in mineral interests to an active and material participant in oil & gas minerals.

Beginning in 2019, ARLP transitioned from a passive investor in mineral interests to an active and material participant in oil & gas minerals.

Permian Basin—Delaware and Midland Basins

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The Appalachia Basin's most active plays in which we have acreage are the Marcellus Shale and Utica plays, which cover most of Pennsylvania, northern West Virginia, and eastern Ohio.

In addition to the interests held in the Appalachia Basin, we own a small amount of mineral interests in the Tuscaloosa Marine Shale play in Mississippi.

In addition to the interests held in the Appalachia Basin, we own a small number of mineral interests in the Tuscaloosa Marine Shale play in Mississippi.

AllDale III also owns mineral interests in the Haynesville Shale formation located in northwest Louisiana.

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These alternate forms of energy include electricity, coal, and fuel oils.

Changes in the availability or price of oil & gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil & gas.

Changes in the availability or price of oil & gas or other forms of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternative fuels and other forms of energy, may affect the demand for oil & gas.

Minerals - Seasonal Nature of Business

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We have a policy of matching our outside coal purchases and sales to minimize market risks associated with buying and reselling coal.

In 2019, we made outside coal purchases for brokerage activity of 479,764 tons.

Design entities and Alliance Design are referred to as the "Matrix Group"), provide a variety of mining technology products and services for our mining operations and certain industrial and mining technology products and services to third parties.

Our subsidiaries, Matrix Design Group, LLC ("Matrix Design") and its subsidiaries Matrix Design International, LLC and Matrix Design Africa (PTY) LTD, and Alliance Design Group, LLC ("Alliance Design") (collectively the Matrix Design entities and Alliance Design are referred to as the "Matrix Group"), provide a variety of mining technology products

and services for our mining operations and certain industrial and mining technology products and services to third parties.

Matrix Group's products and services include miner and equipment tracking systems and proximity detection systems.

We acquired Matrix Design in September 2006.

Compression Investment

On July 19, 2017, Alliance Minerals purchased $100 million of Series A-1 Preferred Interests from Kodiak, a privately held company providing large-scale, high-utilization gas compression assets to customers operating primarily in the Permian Basin.

On February 8, 2019, Kodiak redeemed the preferred interests held by Alliance Minerals for $135.0 million cash that is inclusive of an early redemption premium.

Additional Services

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The regulatory burden on fossil-fuel industries increases the cost of doing business and consequently affects profitability.

The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly obligations could increase our or our mineral interest operators’ costs and adversely affect our performance.

In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which has adversely affected demand for coal.

The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or reinterpretation of enforcement policies that result in more stringent and costly obligations could increase our or our mineral interest operators’ costs and adversely affect our performance.

In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which has adversely affected the demand for coal.

It is possible that new legislation or regulations may be adopted, or that existing laws or regulations may be differently interpreted or more stringently enforced, any of which could have a significant impact on our mining operations, our customers' ability to use coal, or the value of or amount of royalties received from our mineral interests.

For more information, please see risk factors described in "Item 1A.

For more information, please see the risk factors described in "Item 1A.

Risk Factors"

We are committed to conducting mining operations in compliance with applicable federal, state, and local laws and regulations.

to fault and many of the standards include subjective elements, it is not reasonable to expect any coal mining company to be free of citations.

However, because of the extensive and detailed nature of these regulatory requirements, particularly the regulatory system of the Mine Safety and Health Administration ("MSHA") where citations can be issued without regard to fault and many of the standards include subjective elements, it is not reasonable to expect any coal mining company to be free of citations.

When we receive a citation, we attempt to promptly remediate any identified condition.

1 unchanged sentence

Compliance with these laws and regulations has substantially increased the cost of coal mining for domestic coal producers.

Capital expenditures for environmental matters have not been material in recent years.

We have accrued for the present value of the estimated cost of asset retirement obligations and mine closings, including the cost of treating mine water discharge, when necessary.

The accruals for asset retirement obligations and mine closing costs are based upon permit requirements and the costs and timing of asset retirement obligations and mine closing procedures.

Expenditures for environmental matters have not been material in recent years.

We have accrued for the present value of the estimated cost of asset retirement obligations and mine closings, including the cost of treating mine water discharge,

when necessary.

The accruals for asset retirement obligations and mine closing costs are based upon permit requirements and the estimated costs and timing assumptions of asset retirement obligations and mine closing procedures.

Although management believes it has made adequate provisions for all expected reclamation and other costs associated with mine closures, future operating results would be adversely affected if these accruals were insufficient.

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Meeting all requirements imposed by any of these authorities may be costly and time-consuming, and may delay or prevent commencement or continuation of mining operations.

The permitting process for certain mining operations can extend over several years and can be subject to administrative and judicial challenge, including by the public.

The permitting process for certain mining operations can extend over several years and can be subject to administrative and judicial challenges, including by the public.

Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all.

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In addition, most of the states where we operate have state programs for mine safety and health regulation and enforcement.

Federal and state safety and health regulations affecting the coal mining industry are perhaps the most comprehensive and rigorous system in the United States for protection of employee safety and have a significant effect on our operating costs.

Federal and state safety and health regulations affecting the coal mining industry are perhaps the most comprehensive and rigorous system in the United States for the protection of employee safety and have a significant effect on our operating costs.

Although many of the requirements primarily impact underground mining, our competitors in all of the areas in which we operate are subject to the same laws and regulations.

FMSHA has been construed as authorizing MSHA to issue citations and orders pursuant to the legal doctrine of strict liability, or liability without fault, and FMSHA requires imposition of a civil penalty for each cited violation.

Negligence and gravity assessments, and other factors can result in the issuance of various types of orders, including orders requiring withdrawal from the mine or the affected area, and some orders can also result in the imposition of civil penalties.

FMSHA has been construed as authorizing MSHA to issue citations and orders pursuant to the legal doctrine of strict liability, or liability without fault, and FMSHA requires the imposition of a civil penalty for each cited violation.

Negligence and gravity assessments, along with other factors, can result in the issuance of various types of orders, including orders requiring withdrawal from the mine or the affected area, and some orders can also result in the imposition of civil penalties.

FMSHA also contains criminal liability provisions.

For example, criminal liability may be imposed upon corporate operators who knowingly and willfully authorize, order, or carry out violations of the FMSHA, or its mandatory health and safety standards.

a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities.

The Federal Mine Improvement and New Emergency Response Act of 2006 ("MINER Act") significantly amended the FMSHA, imposing more extensive and stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities.

Following the passage of the MINER Act, MSHA has issued new or more stringent rules and policies on a variety of topics, including:

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It is uncertain whether MSHA will present additional proposed rules, or revisions to the final rule, following the closing of the comment period for the current request for information.

Additionally, in July 2014, MSHA proposed a rule addressing the "criteria and procedures for assessment of civil penalties."

Public commenters have expressed concern that the proposed rule exceeds MSHA's rulemaking authority and would result in substantially increased civil penalties for regulatory violations cited by MSHA.

MSHA last revised the process for proposing civil penalties in 2006 and, as discussed above, civil penalties increased significantly.

The notice-and-comment period for this proposed rule closed, and it is uncertain when, or if, MSHA will present a final rule addressing these civil penalties.

In January 2015, MSHA published a final rule requiring mine operators to install proximity detection systems on continuous mining machines, over a staggered time frame ranging from November 2015 through March 2018.

The proximity detection systems initiate a warning or shutdown the continuous mining machine depending on the proximity of the machine to a miner.

MSHA subsequently proposed a rule requiring mine operators to also install proximity detection systems on other types of underground mobile mining equipment.

The comment period for this proposed rule closed on April 10, 2017, and it is uncertain when MSHA will promulgate a final rule addressing the issue of proximity detection systems on underground mobile mining equipment, other than continuous mining machines.

In June 2016, MSHA published a request for information on Exposure of Underground Miners to Diesel Exhaust.

MSHA has also published, and may continue to publish, various proposed rules or requests for information, which may result in additional rulemakings.

For example, in June 2016, MSHA published a request for information on Exposure of Underground Miners to Diesel Exhaust.

Following a comment period that closed in November 2016, MSHA received requests for MSHA and the National Institute for Occupational Safety and Health to hold a Diesel Exhaust Partnership to address the issues covered by MSHA's request for information.

The comment period for the request for information is scheduled to close in September 2020.

The comment period for the request for information closed in September 2020.

It is uncertain whether MSHA will present a proposed rule pertaining to exposure of underground miners to diesel exhaust, after completing its evaluation of the comments received.

In June 2018, MSHA published a request for information on Safety Improvement Technologies for Mobile Equipment at Surface Mines and for Belt Conveyors at Surface and Underground Mines.

The comment period for the request for information has closed.

It is uncertain whether MSHA will present a proposed rule pertaining to safety improvement technologies for mobile equipment at surface mines or for belt conveyors at surface and underground mines.

Subsequent to passage of the MINER Act, Illinois, Kentucky, Pennsylvania and West Virginia have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight.

Separately, in November 2020, MSHA published a proposed rule to revise Testing, Evaluation, and Approval of Electric Motor-Driven Mine Equipment and Accessories within underground mining environments.

The comment period for the proposed rule closed in December 2020.

It is uncertain whether MSHA will present a final rule addressing this issue.

Subsequent to the passage of the MINER Act, Illinois, Kentucky, Pennsylvania, and West Virginia have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight.

Additionally, state administrative agencies can promulgate administrative rules and regulations affecting our operations.

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In addition, the BLBA provides that some claims for which coal operators had previously been responsible are or will become obligations of the government trust funded by the tax.

The Revenue Act of 1987 extended the termination date of this tax from January 1, 1996, to the earlier of January 1, 2014, or the date on which the government trust becomes solvent.

The Revenue Act of 1987

extended the termination date of this tax from January 1, 1996, to the earlier of January 1, 2014, or the date on which the government trust becomes solvent.

The Emergency Economic Stabilization Act of 2008 extended these rates through December 31, 2018.

On January 1, 2019, the excise tax rates reverted to their original 1977 statutory levels of $0.50 per ton for underground-mined coal and $0.25 per ton for surface-mined coal, but not to exceed 2% of the applicable sales price.

In December 2019, the excise tax rates were increased to their 2018 levels and that rate increase is set to expire on December 31, 2020.

In December 2019, the excise tax rates were increased to their 2018 levels and that rate increase was set to expire on December 31, 2020.

However, in December 2020, the excise tax rate increase was extended another year, through December 31, 2021.

Workers ' Compensation and Black Lung

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For more information concerning our requirement to maintain bonds to secure our workers' compensation obligations, see the discussion of surety bonds below under "— Bonding Requirements.

The revised BLBA regulations took effect in January 2001, relaxing the stringent award criteria established under previous regulations and thus potentially allowing new federal claims to be awarded and allowing previously denied claimants to re-file under the revised criteria.

These regulations may also increase black lung-related medical costs by broadening the scope of conditions for which medical costs are reimbursable and increase legal costs by shifting more of the burden of proof to the employer.

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We believe we are in compliance in all material respects with applicable regulations relating to reclamation.

In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977.

The tax for surface-mined and underground-mined coal is $0.28 per ton and $0.12 per ton, respectively.

In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a reclamation fee on all current mining operations, the proceeds of which are used to restore mines closed before 1977.

The fee for surface-mined and underground-mined coal is $0.28 per ton and $0.12 per ton, respectively.

This fee is currently scheduled to be in effect until September 30, 2021, and requires Congressional action to reauthorize.

We have accrued the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary.

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however, the final rule does not address the placement of CCRs in minefills or non-minefill uses of CCRs at coal mine sites.

OSM has announced their intention to release a proposed rule to regulate placement and use of CCRs at coal mine sites, but, to date, no further action has been taken.

The Federal Office of Surface Mining ("OSM") has announced their intention to release a proposed rule to regulate placement and use of CCRs at coal mine sites, but, to date, no further action has been taken.

These actions by OSM, potentially could result in additional delays and costs associated with obtaining permits, prohibitions or restrictions relating to mining activities, and additional enforcement actions.

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These bonds are typically renewable on a yearly basis.

It has become increasingly difficult for us and for our competitors to secure new surety bonds without posting collateral.

It has become increasingly difficult for us and for our competitors to secure new surety bonds without posting collateral and in some cases it is unclear what level of collateral will be required.

By example, the Office of Workers' Compensation Programs issued new criteria in 2019, but has yet to provide information to self-insured operators regarding the bonding levels and collateral thresholds that will be required.

In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us.

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There have been a series of federal rulemakings focused on emissions from coal-fired electric generating facilities.

Installation of additional emissions control technology and any additional measures required under applicable federal and state laws and regulations related to

air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and, depending on the requirements of individual state implementation plans ("SIPs"), could make fossil fuels a less attractive fuel alternative in the planning and building of power plants in the future.

Installation of additional emissions control technology and any additional measures required under applicable federal and state laws and regulations related to air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and, depending on the requirements of individual state implementation plans ("SIPs"), could make fossil fuels a less attractive fuel alternative in the planning and building of power plants in the future.

A significant reduction in fossil fuels’ share of power generating capacity could have a material adverse effect on our business, financial condition, and results of operations.

Since 2010, utilities have completed or formally announced the retirement or conversion of almost 700 coal-fired electric generating units through 2030 in the United States.

In addition to the greenhouse gas ("GHG") issues discussed below, the air emissions programs that may affect our operations or the operations of those on the properties in which we hold mineral interests, directly or indirectly, include, but are not limited to, the following:

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Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions.

In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA's Acid Rain Program by switching to lower-sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or "scrubbers,"

control devices such as flue gas desulfurization systems, or "scrubbers,"

or by reducing electricity-generating levels.

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CSAPR has become increasingly irrelevant with continuing coal plant retirements making the nitrogen oxide ozone budget less stringent and lowering emission allowance prices to levels closer to average operating cost for many of our customers.

The full impact of CSAPR are unknown at the present time due to the implementation of Mercury and Air Toxic Standards ("MATS"), discussed below, and the impact of the continuing coal plant retirements.

The full impacts of CSAPR are unknown at the present time due to the implementation of Mercury and Air Toxic Standards ("MATS"), discussed below, and the impact of the continuing coal plant retirements.

● In February 2012, the EPA adopted the MATS, which regulates the emission of mercury and other metals, fine particulates, and acid gases such as hydrogen chloride from coal and oil-fired power plants.

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In December 2018, the EPA issued a proposed Supplemental Cost Finding, as well as the CAA required "risk and technology review."

In May 2020, EPA issued a final rule that reverses the Agency’s prior determination from 2000 and 2016 that it was "appropriate and necessary"

to regulate hazardous air pollutants ("HAP") from coal-fueled Electric Generating Units ("EGUs") under the MATS rule.

Notwithstanding the invalidation of this threshold regulatory determination, the final rule leaves in place all of the HAP emission control requirements imposed by the MATS rule based on the conclusion that the EGU source category cannot meet the statute's stringent requirements for delisting a source category from HAP regulation.

Many electric generators have already announced retirements due to the MATS rule.

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We continue to evaluate the possible scenarios associated with CSAPR Update and MATS and the effects they may have on our business and our results of operations, financial condition, or cash flows.

● The EPA is required by the CAA to periodically re-evaluate the available health effects information to determine whether the National Ambient Air Quality Standards ("NAAQS") should be revised.

Pursuant to this process, the EPA has adopted more stringent NAAQS for fine particulate matter ("PM"), ozone, nitrogen

oxide, and sulfur dioxide.

● The EPA is required by the CAA to periodically reevaluate the available health effects information to determine whether the National Ambient Air Quality Standards ("NAAQS") should be revised.

Pursuant to this process, the EPA has adopted more stringent NAAQS for fine particulate matter ("PM"), ozone, nitrogen oxide, and sulfur dioxide.

As a result, some states will be required to amend their existing SIPs to attain and maintain compliance with the new air quality standards and other states will be required to develop new SIPs for areas that were previously in "attainment"

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In addition, under the revised ozone NAAQS, significant additional emissions control expenditures may be required at coal-fired power plants.

Initial non-attainment determinations related to the revised sulfur dioxide standard became effective in October 2013.

In addition, in January 2013, the EPA updated the NAAQS for fine particulate matter emitted by a wide variety of sources including power plants, industrial facilities, and gasoline and diesel engines, tightening the annual PM 2.5 standard to 12 micrograms per cubic meter.

The revised standard became effective in March 2013.

In November 2013, the EPA proposed a rule to clarify PM 2.5 implementation requirements to the states for current 1997 and 2006 non-attainment areas.

In July 2016, the EPA issued a final rule for states to use in creating their plans to address particulate matter.

In October 2015, the EPA published a final rule that reduced the ozone NAAQS from 75 to 70 ppb and completed attainment/non-attainment designations in July 2018.

In March 2019, the EPA published a final rule that retained the current primary NAAQS for sulfur oxide.

In December 2020, EPA published a final rule to retain the current NAAQS for both PM and ozone;

however, various entities have filed litigation against one or both of these rulemakings, and the NAAQS may be subject to revision under the Biden Administration.

New standards may impose additional emissions control requirements on new and expanded coal-fired power plants and industrial boilers.

Because coal mining operations and coal-fired electric generating facilities emit particulate matter and sulfur dioxide, our mining operations and our customers could be affected when the new standards are implemented by the applicable states, and developments might indirectly reduce the demand for coal.

Separately, implementation of new standards by states has a potential to delay or otherwise impact oil & gas production activities, which could reduce the profitability of our mineral interests.

applicable states, and developments could indirectly reduce the demand for coal.

Separately, the implementation of new standards by states has the potential to delay or otherwise impact oil & gas production activities, which could reduce the profitability of our mineral interests.

● The EPA's regional haze program is designed to protect and improve visibility at and around national parks, national wilderness areas, and international parks.

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Several of these lawsuits have settled, but others remain pending.

In addition, there are proposals to modify the NSR program as a part of the Affordable Clean Energy ("ACE") rule, which is subject to current pending litigation as discussed below .

A final rule on NSR reforms is expected in March 2020.

In October 2020, the EPA finalized a rule to clarify the process for evaluating whether the NSR permitting program would apply to a proposed modification of a source of air emissions.

Depending on the ultimate resolution of these cases, demand for coal could be affected.

● The EPA’s New Source Performance Standards ("NSPS") under the CAA require the reduction of volatile organic compounds and methane emissions from certain stimulated oil & gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as "green completions.

● The EPA’s New Source Performance Standards ("NSPS") under the CAA require the reduction of certain pollutants and methane emissions from certain stimulated oil & gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as "green completions."

These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels.

Subsequently, the Trump Administration has made several attempts to modify CAA regulations related to methane emissions from oil & gas sources.

These attempts are subject to ongoing litigation.

Most recently, in August 2019, the EPA proposed amendments to the existing methane requirements that, among other things, could rescind methane-specific requirements applicable to upstream facilities but retain requirements for volatile organic compound emissions.

Legal challenges to any final rule rescinding federal methane requirements is expected.

Although the Trump Administration revised prior regulations in September 2020 to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations, President Biden signed an executive order on his first day in office calling for the suspension, revision, or rescission of the September 2020 rule and the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and gas facilities.

Oil & gas production on the properties in which we hold mineral interests could be adversely affected to the extent any final rule imposes increased operating costs on the oil & gas industry.

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Future regulation of GHG emissions in the United States could occur pursuant to future United States treaty commitments, new domestic legislation, or regulation by the EPA.

Former President Obama expressed support for a mandatory cap and trade program to restrict or regulate emissions of GHGs and Congress has considered various proposals to reduce GHG emissions, and it is possible federal legislation could be adopted in the future.

Internationally, there is an international climate agreement (the "Paris Agreement") that does not create any binding obligations for nations to limit their GHG emissions but includes pledges to voluntarily limit or reduce future emissions.

Although no comprehensive climate change regulation has been adopted at the federal level in the United States, President Biden has announced that climate change will be a focus of his administration.

For example, in January 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil-fuel industry, a doubling of electricity generated by offshore wind by 2030, and increased emphasis on climate-related risks across governmental agencies and economic sectors.

Internationally, the Paris Agreement requires member states to submit non-binding, individually-determined emissions reduction targets.

These commitments could further reduce demand and prices for fossil fuels.

In November 2019, the United States announced its withdrawal from such agreement, effective November 4, 2020.

However, the United States may subsequently decide to rejoin the Paris Agreement or another agreement at some point in the future.

Moreover, many states, regions, and governmental bodies have adopted GHG initiatives and have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities, including coal-fired electric generating facilities.

Although the United States had withdrawn from the Paris Agreement, President Biden has signed executive orders recommitting the United States to the agreement and calling for the federal government to begin formulating the United States’ nationally determined emissions reduction targets under the agreement.

However, the impact of these orders, and the terms of any legislation or regulation to implement the United States’ commitment under the Paris Agreement, remain unclear at this time.

fired electric generating facilities.

Others have announced their intent to increase the use of renewable energy sources, displacing coal and other fossil fuels.

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Although the United States Supreme Court's holding did not expressly involve the EPA's authority to regulate GHG emissions from stationary sources, such as coal-fueled power plants, the EPA has determined on its own that it has the authority to regulate GHG emissions from power plants and issued a final rule which found that GHG emissions, including carbon dioxide and methane, endanger both the public health and welfare.

On September 20, 2013, the EPA issued NSPS for carbon dioxide emissions from new fossil fuel-fired power plants.

This rule was finalized in 2015 and was immediately challenged by multiple parties.

In August 2017, this rule was stayed by a federal appeals court to allow the Trump administration's EPA to review the NSPS rule.

It is likely than any repeal or revisions to the NSPS will be subject to legal challenges as well.

Future implementation of the NSPS is uncertain at this time.

Several rulemakings have been issued under the NSPS that constrain the GHG emissions of fossil-fuel-fired power plants.

Most recently, in January 2021, the EPA published a final significant contribution finding for purposes of regulating source category of GHG emissions, confirming that such power plants are a source category for such regulations.

However, this finding also excludes several sectors and may, therefore, be subject to revision, and future implementation of the NSPS is uncertain at this time.

In August 2015, the EPA issued its final Clean Power Plan ("CPP") rules that establish carbon pollution standards for power plants, called CO2 emission performance rates.

Judicial challenges led the United States Supreme Court to grant a stay in February 2016 of the implementation of the CPP before the United States Court of Appeals for the District of Columbia ("Circuit Court") even issued a decision.

Additionally, in October 2017 the EPA proposed to repeal the CPP, although the final outcome of this action and the pending litigation regarding the CPP is uncertain at this time.

Then, in October 2017 the EPA proposed to repeal the CPP.

The EPA subsequently proposed the ACE rule to replace the CPP with a rule that utilizes heat rate improvement measures as the "best system of emission reduction".

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and, the rule revises the NSR permitting program to provide EGUs the opportunity to make efficiency improvements without triggering NSR permit requirements.

In June 2019, the EPA published the final repeal of the Clean Power Plan and promulgation of the ACE rule.

The EPA's attempts to replace the CPP with the ACE rule are currently subject to litigation, and we cannot predict the final outcome.

Notwithstanding the ACE rule, these requirements have led to premature retirements and could lead to additional premature retirements of coal-fired generating units and reduce the demand for coal.

In June 2019, the EPA published the final repeal of the CPP and promulgation of the ACE rule.

The EPA's attempts to replace the CPP with the ACE rule are currently subject to litigation, and on January 19, 2021, the Circuit Court struck down the ACE rule, though the case is not yet final and we cannot predict the outcome of the litigation.

Notwithstanding the ACE rule, requirements have led to premature retirements and could lead to additional premature retirements of coal-fired generating units and reduce the demand for coal.

Congress has not currently adopted legislation to restrict carbon dioxide emissions from existing power plants and it is unclear whether the EPA has the legal authority to regulate carbon dioxide emissions from existing and modified power plants as proposed in the NSPS and CPP.

Substantial limitations on GHG emissions could adversely affect demand for the coal we produce or the oil & gas produced from our mineral interests.

There have been numerous protests of and challenges to the permitting of new fossil fuel infrastructure, including power plants and pipelines, by environmental organizations and state regulators for concerns related to GHG emissions.

There have been numerous protests and challenges to the permitting of new fossil-fuel infrastructure, including power plants and pipelines, by environmental organizations and state regulators for concerns related to GHG emissions.

For instance, various state regulatory authorities have rejected the construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with GHG emissions from these plants under future laws limiting the emissions of carbon dioxide.

In addition, several permits issued to new coal-fueled power plants without limits on

GHG emissions have been appealed to the EPA's Environmental Appeals Board.

In addition, several permits issued to new coal-fueled power plants without limits on GHG emissions have been appealed to the EPA's Environmental Appeals Board.

In addition, over thirty states have currently adopted "renewable energy standards"

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Other states may adopt similar requirements, and federal legislation is a possibility in this area.

To the extent these requirements affect our current and prospective customers, or those of our mineral interest producers, they may reduce the demand for fossil fuel energy, and may affect long-term demand for our coal and the oil & gas producers from the properties in which we hold mineral interests.

To the extent these requirements affect our current and prospective customers or those of our mineral interest producers, they may reduce the demand for fossil-fuel energy, and may affect the long-term demand for our coal and the oil & gas producers from the properties in which we hold mineral interests.

Finally, while the United States Supreme Court has held that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions, the Court did not decide whether similar claims can be brought under state common law.

As a result, despite this favorable ruling, tort-type liabilities remain a concern.

For more information, see our risk factor titled "We, our customers, or the operators of our oil & gas mineral interests could be subject to litigation related to climate change."

In addition, environmental advocacy groups have filed a variety of judicial challenges claiming that the environmental analyses conducted by federal agencies before granting permits and other approvals necessary for certain coal activities do not satisfy the requirements of the National Environmental Policy Act ("NEPA").

These groups assert that the environmental analyses in question do not adequately consider the climate change impacts of these particular projects.

In January 2020, the CEQ issued a proposed revision to NEPA regulations that seeks to clarify the extent to which direct, indirect, and cumulative environmental impacts from a proposed project, including GHG emissions, should be examined under NEPA;

however, the final form or impact of any such revisions is uncertain at this time.

July 2020, the Council on Environmental Quality finalized revisions to NEPA regulations that clarify the extent to which direct, indirect, and cumulative environmental impacts from a proposed project, including GHG emissions, should be examined under NEPA;

however, these regulations may be subject to further regulation under the Biden Administration.

Many states and regions have adopted GHG initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHG by certain facilities, including coal-fired electric generating facilities.

For example, in 2005, ten Northeastern states entered into the Regional Greenhouse Gas Initiative agreement ("RGGI"), calling for implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states.

For example, in 2005, ten Northeastern states entered into the Regional Greenhouse Gas Initiative agreement ("RGGI"), calling for the implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states.

The members of RGGI have established in statutes and/or regulations a carbon dioxide trading program.

Auctions for carbon dioxide allowances under the program began in September 2008.

Since its inception, several additional northeastern states and Canadian provinces have joined RGGI as participants or observers.

In 2019, New Jersey and Pennsylvania each announced they were joining RGGI.

Since its inception, several additional states and Canadian provinces have joined RGGI as participants or observers.

Following the RGGI model, five Western states launched the Western Regional Climate Action Initiative to identify, evaluate, and implement collective and cooperative methods of reducing GHG in the region to 15% below 2005 levels by 2020.

These states were joined by two additional states and four Canadian provinces and became collectively known as the Western Climate Initiative Partners.

However, as of 2020, only California and the Canadian provinces of British Columbia, Novia Scotia, and Quebec.

Nevertheless, it is likely that these regional efforts will continue based on current trends and concerns related to the reduction of GHG emissions.

These states were joined by two additional states and four Canadian provinces and became collectively known as the Western Climate Initiative Partners, though only California and certain Canadian provinces are currently active participants in the Western Climate Initiative.

It is likely that these regional efforts will continue based on current trends and concerns related to the reduction of GHG emissions.

It is possible that future international, federal, and state initiatives to control GHG emissions could result in increased costs associated with fossil-fuel production and consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs.

Such increased costs for fossil-fuel consumption could result in some customers switching to alternative sources of fuel, or otherwise adversely affect our operations and demand for our products, or those of the operators of our mineral interests, which could have a material adverse effect on our business, financial condition, and results of operations Finally, activists may try to hamper fossil-fuel companies by other means, including pressuring financing and other institutions into restricting access to capital, bonding, and insurance, as well as pursuing tort litigation for various alleged climate-related impacts.

For more information, see our Risk Factor titled "Our operations are subject to a series of risks resulting from climate change."

Water Discharge

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For more information about asset retirement obligations, please read "Item 8.

Financial Statements

and Supplementary Data—Note 18 - Asset Retirement Obligations."

Financial Statements and Supplementary Data—Note 18 - Asset Retirement Obligations."

Although more stringent permitting requirements may be imposed in the future, we are not able to accurately predict the impact, if any, of such permitting requirements.

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1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia.

This action was the first time that such power was exercised with regard to a previously permitted coal mining project.

A challenge to the EPA's exercise of this authority was made in the United States District Court for the District of Columbia and in March 2012, that court ruled that the EPA lacked the statutory authority to invalidate an already issued Section 404 permit retroactively.

In April 2013, the D.C.

Circuit Court of Appeals reversed this decision and authorized the EPA to retroactively veto portions of a Section 404 permit.

The United States Supreme Court denied a request to review this decision.

This action was the

first time that such power was exercised with regard to a previously permitted coal mining project which veto was subsequently upheld by the D.C.

Circuit Court of Appeals in 2013.

Any future use of the EPA's Section 404 "veto"

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The implications of this decision could allow the EPA to bypass the state permitting process and engage in watershed and land use planning.

In June 2018, the EPA Administrator issued a memorandum directing the EPA's Office of Water to promulgate draft regulations eliminating the use of the EPA's Section 404 authority before a Section 404 permit application has been filed, or after a permit has been issued.

To date, the EPA has not issued a proposed rule.

Total Maximum Daily Load ("TMDL") regulations under the CWA establish a process to calculate the maximum amount of a pollutant that an impaired water body can receive and still meet state water quality standards, and to allocate pollutant loads among the point and non-point pollutant sources discharging into that water body.

Total Maximum Daily Load ("TMDL") regulations under the CWA establish a process to calculate the maximum amount of a pollutant that an impaired waterbody can receive and still meet state water quality standards, and to allocate pollutant loads among the point and non-point pollutant sources discharging into that water body.

Likewise, when water quality in a receiving stream is better than required, states are required to conduct an antidegradation review before approving discharge permits.

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Considerable legal uncertainty exists surrounding the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the CWA.

A 2015 rulemaking by the EPA to revise the standard was quickly challenged and nationwide implementation was blocked by a federal appeals court.

Should the 2015 rule take effect, or should a different rule expanding the definition of what constitutes a water of the United States be promulgated as a result of the EPA and the Corps of Engineers' rulemaking process, we could face increased costs and delays due to additional permitting and regulatory requirements and possible challenges to permitting decisions.

In December 2018, the EPA and the Corps of Engineers issued a proposed rule to "determine the scope of 'waters of the United States' "subject to federal jurisdiction.

This proposal would lessen the number of waterbodies subject to the CWA as compared to the 2015 Rule.

In January 2020, the EPA finalized its rule regarding the scope of "Waters of the United States."

Litigation surrounding these developments is ongoing and we cannot predict the outcome at this time.

Rulemakings to establish the extent of such jurisdiction were finalized in 2015 and 2020, respectively, and both rulemakings have been subject to substantial litigation.

It is also possible that Biden Administration could propose a broader definition of WOTUS.

Should any rule expanding the definition of what constitutes a water of the United States take effect as a result of the EPA and the Corps of Engineers' rulemaking process, we could face increased costs and delays due to additional permitting and regulatory requirements and possible challenges to permitting decisions.

Hazardous Substances and Wastes

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Persons who are or were responsible for the release of hazardous substances may be subject to joint and several liability under CERCLA for the costs of cleaning up releases of hazardous substances and natural resource damages.

Some products used in coal

mining operations generate waste containing hazardous substances.

Some products used in coal mining operations generate waste containing hazardous substances.

We are currently unaware of any material liability associated with the release or disposal of hazardous substances from our past or present mine sites.

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Many mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by SMCRA permits are by statute exempted from RCRA permitting.

Similarly, most wastes associated with the exploration, development, and production of oil & gas are exempt from regulation as hazardous wastes under RCRA, though these wastes typically constitute “solid wastes” that are subject to less stringent non-hazardous waste requirements.

that are subject to less stringent non-hazardous waste requirements.

However, it is possible that RCRA could be amended or the EPA or state environmental agencies could adopt policies to require such wastes to become subject to more stringent storage, handling, treatment, or disposal requirements, which could impose significant additional costs on the operators of the properties in which we own oil & gas mineral interests.

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waste and avoids the stricter, more costly, regulations under RCRA's "hazardous"

While classification of CCB as a hazardous waste would have led to more stringent restrictions and higher costs, this regulation may still increase our customers' operating costs and potentially reduce their ability to purchase coal.

While the classification of CCB as a hazardous waste would have led to more stringent restrictions and higher costs, this regulation may still increase our customers' operating costs and potentially reduce their ability to purchase coal.

On November 3, 2015, the EPA published the final rule Effluent Limitations Guidelines and Standards ("ELG"), revising the regulations for the Steam Electric Power Generating category which became effective on January 4, 2016.

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In November 2019, the EPA proposed revisions to the 2015 ELG rule and announced proposed changes to regulations for the disposal of coal ash in order to reduce compliance costs.

In October 2020, EPA published a final rule.

It is unclear what impact these regulations will have on the market for our products.

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Some monitoring equipment that we use is subject to licensing under the Federal Atomic Energy Act.

Water supply wells located on our properties are subject to federal, state, and local regulation.

Water supply wells located on our properties are subject to federal, state, and local regulations.

In addition, our use of explosives is subject to the Federal Safe Explosives Act.

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The costs of compliance with these regulations should not have a material adverse effect on our business, financial condition, or results of operations.

Human Capital

To conduct our operations, as of December 31, 2020, we employed 2,902 full-time employees, including 2,530 employees involved in active mining operations, 203 employees in other operations, and 169 corporate employees.

Our work force is entirely union-free.

Our workforce is entirely union-free.

Our typical employee has approximately nine years of experience with the Partnership and more than 34% of all employees remain employed for more than five years.

However, we reduced our headcount by 19% during 2020 primarily due to the effects of the COVID-19 pandemic.

To attract and retain the most qualified personnel across all functions of our business we offer competitive compensation packages.

In making decisions regarding employee compensation, we review current compensation levels for each position within other companies in the coal industry and other peers and use our discretion to determine an appropriate total compensation package, which generally includes a base salary, incentive bonus, medical, dental and life insurance and participation in our profit sharing and savings plan.

Depending on the position, incentive bonuses can be based on production and safety goals at specific coal operations or company-wide performance goals, among other factors.

We intend for each employee's total compensation to be competitive in the marketplace.

Workplace safety is fundamental to our culture.

By providing a work environment that rewards safety and encourages employee participation in the safety process, we strive to be the leader in safety performance in the coal mining industry.

We are focused on improving employee safety through regular training and continuous monitoring of our progress, including through the mining industry standard of "non-fatal days lost,"

or "NFDL,"

which reflects both the frequency and severity of injuries incurred.

Our NFDL rating of 1.06 for the nine months ended September 30, 2020, was approximately 68.6% lower than the preliminary industry average over the same time period.

We are also regularly inspected by MSHA.

For more information about citations or orders for violations of standards under the FMSHA, as amended by the MINER Act, please see our Exhibit 95.1 to this Annual Report on Form 10-K.

We are focused on the health of our employees.

In addition to providing medical, dental and vision insurance with no out-of-pocket premiums for our employees, we also provide on-site medical clinics to provide medical services to our employees and their families.

Furthermore, at each of our coal operations and corporate offices, we provide a human resource representative to assist employees with various human resource matters.

The Partnership also administers our

medical plan, which allows us to control costs and work directly on behalf of our employees with health care providers enabling us in part, to continue providing health benefits with no out-of-pocket premiums for our employees.

In light of the COVID-19 pandemic in 2020, we have also taken steps to enhance protections from, and minimize risks associated with, the spread of COVID-19, including, but not limited to, staggering shift patterns to promote social distancing, enhanced cleaning procedures, promotion of recommended hygiene practices, limited workplace access, "touch-free"

check-in/check-out stations, wellness screening at mine locations, and requiring face coverings where appropriate.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business