What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2022-02-25 compared with 2021-02-23 · 295 added, 251 removed, 372 unchanged (59% of the section changed)

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Executive Overview

We are a diversified natural resource company that generates income from the production and marketing of coal to major domestic and international utilities and industrial users as well as income from oil & gas mineral interests located in strategic producing regions across the United States.

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.

In addition, the mineral interests we own are in premier oil & gas producing regions of the United States, primarily in the Permian, Anadarko and Williston Basins.

We are a diversified natural resource company that generates operating and royalty income from the production and marketing of coal to major domestic and international utilities and industrial users as well as royalty income from oil & gas mineral interests located in strategic producing regions across the United States.

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

In addition to our mining operations, Alliance Resource Properties owns or leases coal mineral reserves and resources in the Illinois and Appalachia Basins that are (a) leased to our internal mining complexes or (b) near other internal and external coal mining operations.

The oil & gas mineral interests we own are in premier oil & gas producing regions of the United States, primarily in the Permian, Anadarko and Williston Basins.

Our mining operations are located near many of the major eastern utility generating plants and on major coal hauling railroads in the eastern United States.

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Vernon transloading facility are located on the Ohio River.

As of December 31, 2020, we had approximately 1.65 billion tons of proven and probable coal reserves in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia.

As of December 31, 2021, we had approximately 547.1 million tons of proven and probable coal mineral reserves and 1.17 billion tons of measured, indicated and inferred coal mineral resources in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia.

All of our measured, indicated and inferred coal mineral resources and 422.9 million tons of these coal mineral reserves are owned or leased by Alliance Resource Properties, our land holding company.

We believe we control adequate reserves to implement our currently contemplated mining plans.

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Business—Coal Mining Operations"

for further discussion of our mines.

in our Annual Report on Form 10-K for the year ended December 31, 2021 for further discussion of our mines.

In 2021, we sold 32.3 million tons of coal and produced 32.2 million tons.

Of the 32.3 million tons sold, approximately two-thirds was leased from Alliance Resource Properties.

The coal we sold in 2021 was approximately 14.2% low-sulfur coal, 50.3% medium-sulfur coal and 35.5% high-sulfur coal.

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In 2021, approximately 87.7% of our medium- and high-sulfur coal was sold to utility plants with installed pollution control devices.

During 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.

During 2021, approximately 81.6% of our tons sold were purchased by U.S.

electric utilities and 12.5% were sold into the international markets through brokered transactions.

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

Although some utility customers continue to favor a shorter-term contracting strategy, in 2020 we began to see several domestic utilities in the market seeking significant coal supply commitments for multi-year terms.

Although some utility customers continue to favor a shorter-term contracting strategy, in 2021 we have continued to see several domestic utilities in the market seeking significant coal supply commitments for multi-year terms.

Long-term sales contracts contribute to our stability and profitability by providing greater predictability of sales volumes and sales prices.

In 2021, approximately 77.9% of our sales tonnage was sold under long-term sales contracts.

As discussed in more detail in "Item 1A.

Risk Factors,"

On October 13, 2021, AR Midland acquired approximately 1,480 oil & gas net royalty acres in the Delaware Basin from Boulders for a purchase price of $31.0 million in the Boulders Acquisition.

This acquisition enhances our ownership position in the Permian Basin and furthers our business strategy to grow our Oil & Gas Royalties segment.

Following the Boulders Acquisition, we hold approximately 57,000 net royalty acres in premier oil & gas basins including our investment in AllDale III.

For more information, please read "Item 8.

Financial Statement and Supplemental Data—Note 3 – Acquisitions"

of this Annual Report on Form 10-K.

Our results of operations could be impacted by variability in coal sales prices in addition to prices for items that are used in coal production such as steel, electricity and other supplies, unforeseen geologic conditions or mining and processing equipment failures and unexpected maintenance problems, and by the availability or reliability of transportation for coal shipments.

Moreover, the mining regulatory environment in which we operate has grown increasingly stringent as a result of legislation and initiatives pursued during previous administrations.

Additionally, our results of operations could be impacted by our ability to obtain and renew permits necessary for our operations, secure or acquire coal reserves, or find replacement buyers for coal under contracts with comparable terms to existing contracts.

Moreover, the mining regulatory environment in which we operate has grown increasingly stringent as a result of federal and state legislative and regulatory initiatives.

Additionally, our results of operations could be impacted by our ability to obtain and renew permits necessary for our operations, secure or acquire coal mineral reserves and resources, or find replacement buyers for coal under contracts with comparable terms to existing contracts.

As outlined in "Item 1.

Business—Environmental, Health, and Safety Regulations,"

a variety of measures taken by regulatory agencies in the United States and abroad in response to the perceived threat from climate change attributed to GHG emissions could substantially increase compliance costs for us and our customers and reduce demand for fossil fuels including coal which could materially and adversely impact our results of operations.

Business—Environmental, Health, and Safety Regulations", a variety of measures taken by regulatory agencies in the United States and abroad in response to the perceived threat from climate change attributed to GHG emissions could substantially increase compliance costs for us and our customers and reduce demand for fossil fuels including coal which could materially and adversely impact our results of operations.

We are dependent on third-party operators for the exploration, development and production of our oil & gas mineral interests;

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Many of the benefits of our union-free workforce are related to higher productivity and are not necessarily reflected in our direct costs.

In addition, transportation costs may be substantial and are often the determining factor in a coal consumer's contracting decision.

The principal expenses related to our minerals interests business are production and ad valorem taxes.

Our primary business strategy is to create sustainable, capital-efficient growth in available cash to maximize the return of cash to our unitholders by:

● expanding our operations by adding and developing mines and coal reserves in existing, adjacent or neighboring properties;

● extending the lives of our current mining operations through acquisition and development of coal reserves using our existing infrastructure;

In addition, transportation costs, which are mostly borne by our customers, may be substantial and are often the determining factor in a coal consumer's contracting decision.

The principal expenses related to our oil & gas minerals interests business are production and ad valorem taxes.

For our coal royalty interests business, the principal expenses are royalty expenses and production and ad valorem taxes.

Our primary business strategy is to create sustainable, capital-efficient growth in available cash to maximize unitholder returns by:

● expanding our operations by adding and developing mines and coal mineral reserves and resources in existing, adjacent or neighboring properties;

● extending the lives of our current mining operations through acquisition and development of coal mineral reserves and resources using our existing infrastructure;

● continuing to make productivity improvements to remain a low-cost producer in each region in which we operate;

● strengthening our position with existing and future customers by offering a broad range of coal qualities, transportation alternatives and customized services;

● developing strategic relationships to take advantage of opportunities within the coal and oil & gas industries and MLP sector;

● continuing to make investments in oil & gas mineral interests in various geographic locations within producing basins in the continental United States.

As of December 31, 2020, we had three reportable segments:

Illinois Basin, Appalachia and Minerals.

● developing strategic relationships to take advantage of opportunities within the coal and oil & gas industries and in other industries inside and outside of the MLP sector;

● continuing to make investments in oil & gas mineral interests and coal royalty interests in various geographic locations within producing basins in the continental United States.

As of December 31, 2021, we had four reportable segments:

Illinois Basin Coal Operations, Appalachia Coal Operations, Oil & Gas Royalties and Coal Royalties.

We also have an "all other"

category referred to as Other and Corporate.

The two coal reportable segments correspond to major coal producing regions in the eastern United States with similar economic characteristics including coal quality, geology, coal marketing opportunities, mining and transportation methods and regulatory issues.

The Minerals reportable segment includes our oil & gas mineral interests which are located primarily in the Permian (Delaware and Midland), Anadarko (SCOOP/STACK), and Williston (Bakken) basins.

Our ownership in these basins includes approximately 55,500 net royalty acres, which provide us with diversified exposure to industry leading operators consistent with our strategy to grow our oil & gas mineral interest business.

The operations within our Minerals reportable segment primarily include receiving royalties and lease bonuses for our oil & gas mineral interests.

● Illinois Basin reportable segment includes currently operating mining complexes (a) Gibson County Coal's mining complex, which includes the Gibson South mine, (b) Warrior's mining complex, (c) River View's mining complex and (d) the Hamilton mining complex.

The Illinois Basin reportable segment also includes our Mt.

Vernon coal-loading terminal in Indiana which operates on the Ohio River.

The Illinois Basin reportable segment also includes MAC and other support services as well as non-operating mining complexes (a) Gibson North mine, which ceased production in the fourth quarter of 2019, (b) Webster County Coal's Dotiki mining complex, which ceased production in August 2019, (c) White County Coal, LLC's Pattiki mining complex, (d) the Hopkins County Coal mining complex, and (e) Sebree's mining complex.

category referred to as Other, Corporate and Elimination.

The two Coal Operations reportable segments correspond to major coal producing regions in the eastern United States with similar economic characteristics including coal quality, geology, coal marketing opportunities, mining and transportation methods and regulatory issues.

The Oil & Gas Royalties reportable segment includes our oil & gas mineral interests which are located primarily in the Permian (Delaware and Midland), Anadarko (SCOOP/STACK), and Williston (Bakken) basins.

Our ownership in these basins includes approximately 57,000 net royalty acres, which provide us with diversified exposure to industry leading operators consistent with our general strategy to grow our oil & gas mineral interest business.

We market our oil & gas mineral interests for lease to operators in those regions and generate royalty

income from the leasing and development of those mineral interests.

Our Coal Royalties reportable segment includes coal mineral reserves and resources owned or leased by Alliance Resource Properties, which are either a) leased to our mining complexes or (b) near our coal mining operations but not yet leased.

Beginning in the first quarter of 2021, we began to strategically view and manage our coal royalty activities separately from our coal operations since acquiring and managing a variety of royalty producing assets involve similar attributes.

As a result, we restructured our reportable segments to better reflect this strategic view in how we manage our business and allocate resources.

Periods prior to 2021 that are presented herein have been recast to include Alliance Resource Properties within our new Coal Royalties reportable segment with offsetting recast adjustments primarily to our coal operations reportable segments and to a lesser extent, our Other, Corporate and Elimination category.

Eliminations reported in Other, Corporate and Elimination were also recast to reflect intercompany royalty revenues and offsetting intercompany royalty expense resulting from our new Coal Royalties reportable segment.

● Illinois Basin Coal Operations reportable segment includes currently operating mining complexes (a) the Gibson County Coal mining complex, which includes the Gibson South mine, (b) the Warrior mining complex, (c) the River View mining complex and (d) the Hamilton mining complex.

The Illinois Basin Coal Operations reportable segment also includes our Mt.

Vernon coal-loading terminal in Indiana which currently operates on the Ohio River.

The Illinois Basin Coal Operations reportable segment also includes Mid-America Carbonates, LLC ("MAC") and other support services as well as non-operating mining complexes (a) Gibson North mine, which ceased production in the fourth quarter of 2019, (b) Webster County Coal's Dotiki mining complex, which ceased production in August 2019, (c) White County Coal, LLC's Pattiki mining complex, which ceased production in December 2016, (d) the Hopkins County Coal, LLC mining complex, which ceased production in April 2016, and (e) the Sebree mining complex, which ceased production in November 2015.

The non-operating mining complexes are in various stages of reclamation.

● Appalachia reportable segment includes currently operating mining complexes (a) the Mettiki mining complex, (b) the Tunnel Ridge mining complex and (c) the MC Mining mining complex.

● Appalachia Coal Operations reportable segment includes currently operating mining complexes (a) the Mettiki mining complex, (b) the Tunnel Ridge mining complex and (c) the MC Mining mining complex.

The Mettiki mining complex includes Mettiki Coal (WV)'s Mountain View mine and Mettiki Coal (MD)'s preparation plant.

The Tunnel Ridge mining complex mines reserves in both West Virginia and to a lesser extent, Pennsylvania.

The Appalachia reportable segment also includes Penn Ridge assets, which is primarily coal mineral interests.

● Minerals reportable segment includes oil & gas mineral interests held by AR Midland and AllDale I & II, and includes Alliance Minerals equity interest in both AllDale III and Cavalier Minerals.

AR Midland acquired its mineral interests in the Wing Acquisition.

● Oil & Gas Royalties reportable segment includes 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 and Boulders Acquisition.

Please read "Item 8.

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— Note 13 – Investments"

of this Annual Report on Form 10-K for more information on the Wing Acquisition and AllDale III, respectively.

● Other and Corporate includes marketing and administrative activities, the Matrix Group, Alliance Coal's coal brokerage activity and Alliance Minerals' prior equity investment in Kodiak.

In February 2019, Kodiak redeemed our equity investment.

In addition, Other and Corporate includes certain Alliance Resource Properties' land and coal mineral interest activities, Pontiki Coal, LLC's workers' compensation and pneumoconiosis liabilities, Wildcat Insurance, which assists the ARLP Partnership with its insurance requirements, and AROP Funding, LLC ("AROP Funding") and Alliance Resource Finance Corporation ("Alliance Finance").

Please read "Item 8.

Financial Statements and Supplementary Data — Note 8 – Long-term Debt"

— Note 13 – Investments"

of this Annual Report on Form 10-K for more information on AROP Funding, Alliance Finance and Kodiak redemption, respectively.

Market Developments and Our Response for the year ended December 31, 2020

We began the year anticipating our results for the year ended December 31, 2020 would be negatively impacted by challenging coal market conditions primarily due to low natural gas prices, tepid coal demand and the overhang of coal supply.

During the first half of the year, mild weather conditions and deteriorating natural gas prices placed increased pressure on the performance of our coal operations.

Also, during the first half of the year, our Minerals segment results were impacted by natural gas prices remaining low and the collapse in oil prices following actions by the Organization of Petroleum Exporting Countries and Russia.

These downward pressures increased substantially during the first half of the year for both our coal operations and mineral interest activities due to the disruptions to global economies in response to the COVID-19 pandemic resulting in unprecedented demand destruction across all energy markets.

In response to these challenges, we halted production at all of our mining complexes in the Illinois Basin at the end of March and our MC Mining complex in East Kentucky in early April.

With an objective of reducing coal production to match existing contracted sales commitments for 2020, we curtailed production at these operations while continuing to meet customer obligations from coal inventories already produced.

Throughout the first half of 2020 we monitored coal inventories at each location and worked closely with customers to determine when it would be necessary to resume coal production.

Underground production operations resumed in the second quarter at each of our mining complexes and production has continued since that time.

However, several mines continue running at less than capacity due to a limited spot market in the United States and a seaborne market that continues to be sub-economic for United States production, but now showing signs of potential pricing improvements.

Also in response to these market conditions, we took numerous steps to optimize cash flows, reduce working capital requirements and strictly control capital expenditures and expenses.

In addition, the Board of Directors began suspending cash distributions to unitholders with the quarter ended March 31, 2020 and has continued that through the quarter ended December 31, 2020.

The Board of Directors intends to reassess its distribution policy at its meeting following the quarter ending March 31, 2021.

Future unitholder distributions will be subject to ongoing Board of Directors' review of a number of factors including business and market conditions, our future financial and operating performance outlook and other capital allocation priorities.

During the second half of the year we saw improved economic activity, increased coal demand and some recovering oil & gas production volumes and prices which positively impacted our performance compared to the first half of the year.

Higher commodity prices and lower well costs led oil & gas operators to begin bringing previously shut-in wells back online and slowly resume permitting, drilling and completion activity across the regions in which we hold mineral interests.

Impact of the COVID-19 Pandemic

During the year 2020, a variety of measures in the United States and abroad in response to the COVID-19 pandemic resulted in a reduction in the global demand for energy.

These measures included travel restrictions, gathering bans and stay-at-home orders.

All of our operations are classified as essential in the states in which we operate.

Therefore, to protect our employees during the COVID-19 pandemic, we implemented numerous health and safety protocols designed to contain and mitigate the risk of infection from COVID-19.

We continually evaluate the need for further safeguards as the pandemic continues.

As discussed above, we curtailed coal production during the year 2020 in response to global energy demand destruction caused by the COVID-19 pandemic, including the temporary cessation of production at various operations in both the Illinois Basin and Appalachian regions.

In light of the downturn in market conditions during the year 2020 and the ongoing uncertainty surrounding the COVID-19 pandemic, we took the following additional actions:

● To mitigate the reduced revenues from lower coal sales volumes and depressed commodity prices impacting our minerals segment, we took numerous efforts to optimize cash flows, reduce working capital requirements and strictly control capital expenditures, operating expenses and general and administrative expenses.

Our cost control initiatives during the year 2020 resulted in significant reductions in expenses in each of these categories compared to 2019.

The cost reductions are discussed in more detail below.

● On April 26, 2020, the employment of 116 employees of the Gibson County mining complex and 78 employees of the Hamilton mining complex was terminated permanently.

● As stated previously, the Board of Directors began suspending the cash distributions to unitholders with the quarter ended March 31, 2020 and has continued through the quarter ended December 31, 2020.

● In March 2020, we withdrew our initial 2020 operating and financial guidance provided on January 27, 2020, which did not reflect the impact of the COVID-19 pandemic.

● On March 9, 2020, we strengthened our liquidity by entering into a $537.75 million (reducing to $459.5 million on May 23, 2021) revolving credit facility with a termination date of March 9, 2024, replacing the $494.75 million revolving credit facility that was set to expire on May 23, 2021.

of this Annual Report on Form 10-K for more information on the Wing Acquisition and Boulders Acquisition, and AllDale III, respectively.

● Coal Royalties reportable segment includes coal mineral reserves and resources owned or leased by Alliance Resource Properties that are (a) leased to certain of our mining complexes in both the Illinois Basin Coal Operations and Appalachia Coal Operations reportable segments or (b) located near our operations and external mining operations.

Approximately two thirds of the coal sold by our Coal Operations' mines is leased from our Coal Royalties entities.

● Other, Corporate and Elimination includes marketing and administrative activities, the Matrix Group, Pontiki Coal, LLC's workers' compensation and pneumoconiosis liabilities, Wildcat Insurance, which assists the ARLP Partnership with its insurance requirements, AROP Funding, LLC ("AROP Funding") and Alliance Resource Finance Corporation ("Alliance Finance").

Please read "Item 8.

Financial Statements and Supplementary Data — Note 8 – Long-term Debt"

for more information on revolving credit facility.

● We also reduced our total debt by $185.5 million during 2020, further enhancing our liquidity.

We are continuing to monitor and may take further actions to minimize any adverse impact caused by the COVID-19 pandemic.

of this Annual Report on Form 10-K for more information on AROP Funding and Alliance Finance.

How We Evaluate Our Performance

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(2) coal sales price per ton;

(3) BOE produced;

(3) BOE sold;

(4) price per BOE;

(5) coal royalty tons sold;

(6) coal royalty revenue per ton;

(7) Segment Adjusted EBITDA Expense per ton;

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We review price per BOE to evaluate performance against budget and for trend analysis.

Coal Royalty Tons sold .

We monitor and analyze our coal royalty sales volumes from our various mining subsidiaries for coal leased by Alliance Resource Properties for consistency with our Coal Operations segments and for trend analysis.

Coal Royalty Revenue per Ton.

We define coal royalty revenue per ton as total coal royalties divided by royalty tons sold.

We review coal royalty revenue per ton to evaluate consistency with our Coal Operations segments and for trend analysis.

Segment Adjusted EBITDA Expense per Ton.

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2021 Compared with 2020

Total revenues decreased 32.3% to $1.33 billion for 2020 compared to $1.96 billion for 2019 primarily due to lower coal sales and transportation revenues resulting from weak market conditions and disruptions caused by the COVID-19 pandemic.

These lower revenues and a non-cash goodwill impairment charge of $132.0 million partially offset by lower operating expenses, resulted in a net loss attributable to ARLP of $129.2 million for 2020 compared to net income attributable to ARLP of $399.4 million for 2019, which included a net gain of $170.0 million related to the AllDale Acquisition in 2019.

Lower operating expenses and transportation expenses totaled $859.7 million and $21.1 million, respectively, for 2020 compared to $1.18 billion and $99.5 million, respectively, in 2019.

Total revenues increased 18.2% to $1.57 billion, compared to $1.33 billion for 2020 primarily due to increased coal sale volumes and oil & gas prices, which increased 14.4% and 88.2%, respectively.

Higher revenues, lower depreciation and $157.0 million of non-cash impairment charges in 2020, partially offset by higher Segment Adjusted EBITDA Expense, resulted in net income attributable to ARLP of $178.2 million for 2021 compared to a net loss attributable to ARLP of $129.2 million for 2020.

In general, results from coal operations and oil & gas royalties for 2021 were significantly improved compared to 2020, which was impacted by reduced global energy demand and weak commodity prices as a result of lockdown measures imposed in response to the COVID-19 pandemic.

Year Ended December 31,

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(per ton/BOE sold)

Tons produced

Coal - Tons sold

Coal - Tons produced

Coal - Coal sales

Coal - Segment Adjusted EBITDA Expense (1) (2)

Oil & Gas Royalties - BOE sold

Oil & Gas Royalties - Royalties (3)

Coal Royalties - Tons sold

Coal Royalties - Intercompany royalties

(1) For a definition of Segment Adjusted EBITDA Expense and related reconciliation to its comparable GAAP financial measure, please see below under "—Reconciliation of non-GAAP 'Segment Adjusted EBITDA Expense' to GAAP 'Operating Expenses.'"

(2) Coal - Segment Adjusted EBITDA Expense is defined as consolidated Segment Adjusted EBITDA Expense excluding expenses of our Oil & Gas Royalties segment and is adjusted for intercompany transactions with our Coal Royalties segment.

(3) Average sales price per BOE is defined as oil & gas royalty revenues excluding lease bonus revenue divided by total BOE sold.

Coal sales increased $154.7 million or 12.6% to $1.39 billion for 2021 from $1.23 billion for 2020.

The increase was attributable to a volume variance of $177.2 million resulting from increased tons sold partially offset by a negative price variance of $22.5 million due to lower average coal sales prices.

Tons sold increased 14.4% to 32.3 million tons in 2021 due to improved coal demand and increased export shipments.

Primarily due to the expiration of higher priced contract shipments, coal sales price realizations declined 1.6% in 2021 to $42.98 per ton sold, compared to $43.68 per ton sold during 2020.

Production volumes increased by 19.3% in 2021, reflecting the temporary idling and scaling back of production at certain mines during 2020 in response to weak market conditions resulting from the pandemic.

Coal - Segment Adjusted EBITDA Expense .

Segment Adjusted EBITDA Expense for our coal operations increased 10.8% to $975.8 million, as a result of higher coal sales volumes.

On a per ton basis, Segment Adjusted EBITDA Expense for our coal operations decreased 3.2% in 2021 to $30.24 per ton sold, compared to $31.23 per ton in 2020, primarily due to increased volumes lowering fixed costs per ton, a favorable sales mix from our lower cost mines and the impact of ongoing expense control and efficiency initiatives at all of our mining operations in addition to other cost decreases which are discussed below by category:

● Labor and benefit expenses per ton produced, excluding workers' compensation, decreased 11.3% to $9.53 per ton in 2021 from $10.75 per ton in 2020.

The decrease of $1.22 per ton was primarily due to increased volumes at our Illinois Basin mines where production was temporarily idled in 2020 in response to weak market conditions resulting from the pandemic.

● Workers' compensation expenses per ton produced decreased to $0.38 per ton in 2021 from $0.59 per ton in 2020.

The decrease of $0.21 per ton produced resulted from increased production and refunds received in 2021 on assessments paid to the state of Kentucky in prior years, partially offset by unfavorable workers' compensation accrual adjustments in 2021 primarily due to unfavorable changes in claims development.

● Maintenance expenses per ton produced decreased 11.2% to $2.77 per ton in 2021 from $3.12 per ton in 2020.

The decrease of $0.35 per ton produced was primarily due to increased production volumes.

Segment Adjusted EBITDA Expense decreases above were partially offset by the following increase:

● Material and supplies expenses per ton produced increased 4.9% to $10.50 per ton in 2021 from $10.01 per ton in 2020.

The increase of $0.49 per ton produced primarily reflects increases of $0.79 per ton for roof support, $0.21 per ton for contract labor used in the mining process and $0.17 per ton in longwall subsidence expense primarily at our Tunnel Ridge operation, partially offset by decreases of $0.30 per ton for outside expenses used in the mining processes and $0.14 per ton for environmental and reclamation expenses other than longwall subsidence.

Oil & gas royalties .

Oil & gas royalty revenues increased to $75.0 million in 2021 compared to $42.9 million for 2020.

The increase of $32.1 million was primarily due to significantly higher sales price realizations per BOE.

General and administrative.

General and administrative expenses for 2021 increased to $70.2 million compared to $59.8 million in 2020.

The increase of $10.4 million was primarily due to higher incentive compensation expenses.

Depreciation, depletion and amortization.

Depreciation, depletion and amortization expense decreased to $261.4 million for 2021 compared to $313.4 million for 2020 primarily as a result of increased mine life estimates for certain mines and reduced depreciation associated with a) coal inventory changes, b) certain mines closed prior to 2021 and c) lower BOE volumes.

Asset impairments.

During 2020, we recorded $25.0 million of non-cash asset impairment charges due to sealing our idled Gibson North mine, resulting in its permanent closure, and a decrease in the fair value of certain mining equipment and greenfield coal mineral reserves and resources as a result of weakened coal market conditions.

Please read "Item 8.

Financial Statements and Supplementary Data—Note 4 – Long-Lived Asset Impairments."

Goodwill impairment.

During 2020, we recorded a $132.0 million non-cash goodwill impairment charge associated with our Hamilton mine, primarily as the result of reduced expected production volumes due to weakened coal market conditions and low energy demand resulting in part from the COVID-19 pandemic.

Please read "Item 8.

Financial Statements and Supplementary Data— Note 5 – Goodwill Impairment."

Transportation revenues and expenses .

Transportation revenues and expenses were $69.6 million and $21.1 million for 2021 and 2020, respectively.

The increase of $48.5 million was primarily attributable to increased average third-party transportation rates in 2021 and increased coal shipments to international markets for which we arrange third-party transportation.

Transportation revenues are recognized when title to the coal passes to the customer and recognized in an amount equal to the corresponding transportation expenses.

Segment Information .

Our 2021 Segment Adjusted EBITDA increased $102.8 million, or 23.0%, to $549.3 million from 2020 Segment Adjusted EBITDA of $446.5 million.

Segment Adjusted EBITDA, tons sold, coal sales, other revenues, Segment Adjusted EBITDA Expense, oil & gas royalties, BOE volume, coal royalties and coal royalties tons sold by segment are as follows:

Year Ended December 31,

Increase (Decrease)

(in thousands)

Segment Adjusted EBITDA

Illinois Basin Coal Operations

Appalachia Coal Operations

Oil & Gas Royalties

Coal Royalties

Other, Corporate and Elimination (2)

Total Segment Adjusted EBITDA (3)

Coal - Tons sold

Illinois Basin Coal Operations

Appalachia Coal Operations

Total tons sold

Illinois Basin Coal Operations

Appalachia Coal Operations

Total coal sales

Other revenues

Illinois Basin Coal Operations

Appalachia Coal Operations

Oil & Gas Royalties

Coal Royalties

Other, Corporate and Elimination

Total other revenues

Segment Adjusted EBITDA Expense

Illinois Basin Coal Operations

Appalachia Coal Operations

Oil & Gas Royalties

Coal Royalties

Other, Corporate and Elimination (2)

Total Segment Adjusted EBITDA Expense

Oil & Gas Royalties

Volume - BOE (4)

Oil & gas royalties

Coal Royalties

Volume - Tons sold (5)

Intercompany coal royalties

(1) Percentage change not meaningful.

(2) Other, Corporate and Elimination includes the elimination of intercompany coal royalty revenues and expenses between our Coal Royalties Segment and our Coal Operations Segments in addition to the expenses for the other miscellaneous activities included in this category.

(3) For a definition of Segment Adjusted EBITDA and related reconciliation to comparable GAAP financial measures, please see below under "—Reconciliation of non-GAAP "Segment Adjusted EBITDA"

to GAAP "net income (loss)."

(4) BOE for natural gas is calculated on a 6:1 basis (6,000 cubic feet of natural gas to one barrel).

(5) Represents tons sold by our Coal Operations Segments associated with coal mineral reserves leased from our Coal Royalties Segment.

Illinois Basin Coal Operations – Segment Adjusted EBITDA increased 24.0% to $265.3 million in 2021 from $213.9 million in 2020.

The increase of $51.4 million was primarily attributable to higher coal sales, which increased 15.7% to $873.9 million in 2021 from $755.2 million in 2020.

The increase of $118.7 million in coal sales primarily reflects increased sales volumes, which rose 16.5% compared to 2020 due to improved coal demand and increased export volumes reflecting the continued economic recovery from the COVID-19 pandemic.

Increased expenses resulting from higher coal sales volumes, partially offset by ongoing cost control and efficiency initiatives, contributed to higher Segment Adjusted EBITDA Expense of $613.3 million in 2021 compared to $543.3 million in 2020.

Segment Adjusted EBITDA Expense per ton decreased 3.1% to $27.55 from $28.42 per ton sold in 2020 primarily as a result of increased volumes where production was temporarily idled and scaled back in 2020 in response to weak market conditions resulting from the pandemic.

A favorable sales mix from our lower cost mines in 2021 and the impact of ongoing expense control and efficiency initiatives at all of our mining operations in the region also contributed to the decrease.

In addition, also see certain cost variances described above under "–Coal - Segment Adjusted EBITDA Expense."

Appalachia Coal Operations – Segment Adjusted EBITDA increased to $172.6 million for 2021 from $171.4 million in 2020.

The increase of $1.2 million was primarily attributable to higher coal sales, partially offset by lower contract buy-out revenues during 2021.

Coal sales increased 7.5% to $513.0 million in 2021 compared to $477.1 million in 2020 as a result of increased sales volumes, partially offset by lower price realizations.

Tons sold increased 9.9% in 2021 compared to 2020 due to increased sales volumes at our Tunnel Ridge and MC Mining operations resulting from improved market conditions.

Coal sales price per ton sold in 2021 decreased 2.2% compared to 2020 primarily due to the expiration of higher priced contract shipments.

Segment Adjusted EBITDA Expense increased 7.4% in 2021 compared to 2020 due to increased coal sales volumes, partially offset by decreased per ton costs.

Segment Adjusted EBITDA Expense per ton decreased 2.3% to $34.42 compared to $35.24 per ton sold in 2020, as a result of increased sales volumes lowering fixed costs per ton, the full-year production benefit from MC Mining’s transition of mining operations to a new reserve area in the second half of 2020, ongoing expense control and efficiency initiatives and improved recoveries across the region.

See also certain cost variances described above under "–Coal - Segment Adjusted EBITDA Expense."

Oil & Gas Royalties – Segment Adjusted EBITDA increased 72.9% to $68.8 million for 2021 from $39.8 million in 2020.

The increase of $29.0 million was primarily due to significantly higher sales price realizations per BOE, which more than offset lower volumes.

Coal Royalties – Segment Adjusted EBITDA increased 38.5% to $33.2 million for 2021 from $24.0 million in 2020.

The increase of $9.2 million was a result of increased royalty tons sold and higher average coal royalty revenue per ton received from our mining subsidiaries.

Other, Corporate and Elimination – Segment Adjusted EBITDA increased by $11.9 million in 2021 due primarily to increased mining technology product sales from the Matrix Group.

2020 Compared with 2019

Operating expenses and transportation expenses totaled $859.7 million and $21.1 million, respectively, for 2020 compared to $1.18 billion and $99.5 million, respectively, in 2019.

Year Ended December 31,

(in thousands)

(per ton sold)

Coal - Tons sold

Coal - Tons produced

Coal - Coal sales

Coal - Segment Adjusted EBITDA Expense (1) (2)

Oil & Gas Royalties - BOE sold

Oil & Gas Royalties - Royalties (3)

Coal Royalties - Tons sold

Coal Royalties - Intercompany royalties

(2) Coal - Segment Adjusted EBITDA Expense is defined as consolidated Segment Adjusted EBITDA Expense excluding our Minerals segment.

(3) Barrels of oil equivalent ("BOE") for natural gas volumes is calculated on a 6:1 basis (6,000 cubic feet of natural gas to one barrel).

(4) Average sales price per BOE is defined as oil & gas royalties (excluding lease bonus revenue) divided by total BOE.

(3) Average sales price per BOE is defined as oil & gas royalty revenues excluding lease bonus revenue divided by total BOE sold.

Coal sales decreased $530.2 million or 30.1% to $1.23 billion for 2020 from $1.76 billion for 2019.

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Coal sales price realizations declined 2.6% in 2020 to $43.68 per ton sold, compared to $44.86 per ton sold during 2019 resulting, in part, from the absence of high priced metallurgic coal volumes in the 2020 Year.

Coal production volumes fell to 27.0 million tons, a reduction of 32.5% compared to 2019, due to temporarily idling production at certain mines particularly in the Illinois Basin region, in response to weak market conditions during 2020.

Oil & gas royalties .

Oil & gas royalty revenues decreased to $42.9 million in 2020 compared to $51.7 million for 2019.

The decrease was primarily due to lower average product prices, partially offset by higher volumes resulting from the Wing Acquisition in August 2019, and continued drilling and development of our mineral interests.

Coal production volumes fell to 27.0 million tons, a reduction of 32.5% compared to 2019, due to temporarily idling production at certain mines particularly in the Illinois Basin Coal Operations region, in response to weak market conditions during 2020.

Coal - Segment Adjusted EBITDA Expense .

Segment Adjusted EBITDA Expense, excluding our Minerals segment, decreased 28.4% to $857.1 million in 2020, primarily as a result of reduced tons sold.

Segment Adjusted EBITDA Expense for our coal operations decreased 28.6% to $881.0 million in 2020, primarily as a result of reduced tons sold.

Segment Adjusted EBITDA Expense per ton decreased slightly in 2020 to $31.23 per ton, compared to $31.39 per ton in 2019.

The decrease is attributed primarily to ongoing expense control initiatives at all operations, partially offset by the per ton cost impact of lower coal volumes resulting from production curtailment in response to market conditions.

The decrease is attributed primarily to expense control initiatives at all operations, partially offset by the per ton cost impact of lower coal volumes resulting from production curtailment in response to market conditions.

Significant cost control initiatives included the closure of higher cost per ton production at our Dotiki and Gibson North mines.

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export shipments in 2020 compared to 2019.

Oil & gas royalties .

Oil & gas royalty revenues decreased to $42.9 million in 2020 compared to $51.7 million for 2019.

The decrease was primarily due to lower average product prices, partially offset by higher volumes resulting from the Wing Acquisition in August 2019 and continued drilling and development of our mineral interests.

Other revenues .

Other revenues were principally comprised of Mt.

Vernon transloading revenues in our Illinois Basin segment, oil & gas lease bonuses in our Minerals segment and Matrix Design sales in Other & Corporate.

Vernon transloading revenues in our Illinois Basin Coal Operations segment, oil & gas lease bonuses in our Oil & Gas Royalties segment and Matrix Design sales in Other, Corporate and Elimination.

Other revenues also include contract buy-out revenues and other outside services which could occur in any of our segments.

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Asset impairments.

During 2020, we recorded $25.0 million of non-cash asset impairment charges due to sealing our idled Gibson North mine, resulting in its permanent closure, and a decrease in the fair value of certain mining equipment and greenfield coal reserves as a result of weakened coal market conditions.

During 2019, we recorded an asset impairment charge of $15.2 million due to the cessation of production at our Dotiki mine.

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Financial Statements and Supplementary Data—Note 4 – Long-Lived Asset Impairments"

of this Annual Report on Form 10-K.

of this Annual Report on Form 10-K."

Goodwill impairment.

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Equity securities income .

Equity securities income decreased $12.9 million compared to 2019 as we did not recognize equity securities income in 2020 due to the redemption of our preferred interest in Kodiak in 2019.

Equity securities income decreased $12.9 million compared to 2019 as we did not recognize equity securities income in 2020 due to the redemption of our preferred interest in Kodiak Gas Service, LLC ("Kodiak") in 2019.

Acquisition gain .

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Our 2020 Segment Adjusted EBITDA decreased $225.5 million, or 33.6%, to $446.5 million from 2019 Segment Adjusted EBITDA of $672.0 million.

Segment Adjusted EBITDA, tons sold, coal sales, other revenues, oil & gas royalties, BOE volumes and Segment Adjusted EBITDA Expense by segment are as follows:

Year Ended December 31,

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Segment Adjusted EBITDA

Coal - Illinois Basin

Coal - Appalachia

Other and Corporate

Illinois Basin Coal Operations

Appalachia Coal Operations

Oil & Gas Royalties

Coal Royalties

Other, Corporate and Elimination (2)

Total Segment Adjusted EBITDA (3)

Coal - Illinois Basin

Coal - Appalachia

Other and Corporate

Coal - Tons sold

Illinois Basin Coal Operations

Appalachia Coal Operations

Total tons sold

Coal - Illinois Basin

Coal - Appalachia

Other and Corporate

Illinois Basin Coal Operations

Appalachia Coal Operations

Other, Corporate and Elimination

Total coal sales

Other revenues

Coal - Illinois Basin

Coal - Appalachia

Other and Corporate

Total other revenues

BOE volume and oil & gas royalties

Volume - BOE (3)

Illinois Basin Coal Operations

Appalachia Coal Operations

Oil & Gas Royalties

Coal Royalties

Other, Corporate and Elimination

Total other revenues

Segment Adjusted EBITDA Expense

Coal - Illinois Basin

Coal - Appalachia

Other and Corporate

Illinois Basin Coal Operations

Appalachia Coal Operations

Oil & Gas Royalties

Coal Royalties

Other, Corporate and Elimination (2)

Total Segment Adjusted EBITDA Expense

Oil & Gas Royalties

Volume - BOE (4)

Oil & gas royalties

Coal Royalties

Volume - Tons sold (5)

Intercompany coal royalties

(1) Percentage change not meaningful.

(3) For a definition of Segment Adjusted EBITDA and related reconciliation to comparable GAAP financial measures, please see below under "—Reconciliation of non-GAAP "Segment Adjusted EBITDA"

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(4) BOE for natural gas is calculated on a 6:1 basis (6,000 cubic feet of natural gas to one barrel).

Illinois Basin – Segment Adjusted EBITDA decreased 38.5% to $236.9 million in 2020 from $385.2 million in 2019.

(5) Represents tons sold by our Coal Operations Segments associated with coal mineral reserves leased from our Coal Royalties Segment.

Illinois Basin Coal Operations – Segment Adjusted EBITDA decreased 38.9% to $213.9 million in 2020 from $349.8 million in 2019.

The decrease of $135.9 million was primarily attributable to lower coal sales, which decreased 33.1% to $755.2 million in 2020 from $1.13 billion in 2019, partially offset by reduced operating expenses.

The decrease of $373.4 million in coal

sales primarily reflects reduced tons sold, which decreased 32.9% compared to 2019 due to curtailed production across all of our mining operations in the region as a result of weak coal market conditions, particularly international markets, amid the COVID-19 pandemic.

The decrease of $373.4 million in coal sales primarily reflects reduced tons sold, which decreased 32.9% compared to 2019 due to curtailed production across all of our mining operations in the region as a result of weak coal market conditions, particularly international markets, amid the COVID-19 pandemic.

Segment Adjusted EBITDA Expense decreased 31.4% to $543.3 million in 2020 from $791.8 million in 2019 primarily as a result of reduced tons sold.

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In addition, see certain cost per ton and production variances described above under "–Coal - Segment Adjusted EBITDA Expense."

Appalachia – Segment Adjusted EBITDA decreased 20.2% to $172.3 million for 2020 from $216.0 million in 2019.

Appalachia Coal Operations – Segment Adjusted EBITDA decreased 20.4% to $171.4 million for 2020 from $215.2 million in 2019.

The decrease of $43.8 million was primarily attributable to lower coal sales, which decreased 24.1% to $477.1 million in 2020 from $628.4 million in 2019, partially offset by reduced operating expenses.

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See also certain cost variances described above under "–Coal - Segment Adjusted EBITDA Expense."

Minerals – Segment Adjusted EBITDA decreased to $39.8 million for 2020 from $47.0 million in 2019 reflecting reduced average sales price per BOE due to reduced demand amid the COVID-19 pandemic, partially offset by increased production volumes from the additional mineral interests acquired in the Wing Acquisition in August 2019 and from continued drilling and development activities.

Other and Corporate – Segment Adjusted EBITDA decreased by $26.3 million to $6.6 million in 2020 compared to $32.9 million in 2019.

The decrease was primarily attributable to lower equity securities income as a result of the redemption of our preferred interest in Kodiak in 2019, decreased coal brokerage activity and lower mining technology product sales from the Matrix Group.

2019 Compared with 2018

For discussion and analysis of 2019 compared to 2018, please refer to "Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations"

of our Annual Report on Form 10-K for the year ended December 31, 2019, which was filed with the SEC on February 20, 2020 and is incorporated by reference herein.

Oil & Gas Royalties – Segment Adjusted EBITDA decreased to $39.8 million for 2020 from $47.0 million in 2019 reflecting reduced average sales price per BOE due to reduced demand amid the COVID-19 pandemic, partially offset by increased production volumes from the additional mineral interests acquired in the Wing Acquisition in August 2019 and from continued drilling and development activities.

Coal Royalties – Segment Adjusted EBITDA decreased 34.0% to $24.0 million for 2020 from $36.3 million in 2019.

The decrease of $12.3 million was a result of reduced royalty tons sold and lower average coal royalty revenue per ton received from our mining subsidiaries.

Other, Corporate and Elimination – Segment Adjusted EBITDA decreased by $26.2 million in 2020 compared to 2019 due primarily to lower equity securities income as a result of the redemption of our preferred interest in Kodiak in 2019, decreased coal brokerage activity and lower mining technology product sales from the Matrix Group.

Reconciliation of non-GAAP "Segment Adjusted EBITDA"

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to GAAP "Operating Expenses"

Segment Adjusted EBITDA (a non-GAAP financial measure) is defined as net income attributable to ARLP before net interest expense, income taxes, depreciation, depletion and amortization, asset and goodwill impairments, acquisition gain and general and administrative expenses.

Segment Adjusted EBITDA (a non-GAAP financial measure) is defined as net income (loss) attributable to ARLP before net interest expense, income taxes, depreciation, depletion and amortization, asset and goodwill impairments, acquisition gain and general and administrative expenses.

Segment Adjusted EBITDA is a key component of consolidated EBITDA, which is used as a supplemental financial measure by management and by external users of our financial statements such as investors, commercial banks, research analysts and others.

We believe that the presentation of EBITDA provides useful information to investors regarding our performance and results of operations because EBITDA, when used in conjunction with related GAAP financial measures, (i) provides additional information about our core operating performance and ability to generate and distribute cash flow, (ii) provides investors with the financial analytical framework upon which we base financial, operational, compensation and planning decisions and (iii) presents a measurement that investors, rating agencies and debt holders have indicated is useful in assessing us and our results of operations.

upon which we base financial, operational, compensation and planning decisions and (iii) presents a measurement that investors, rating agencies and debt holders have indicated is useful in assessing us and our results of operations.

Segment Adjusted EBITDA is also used as a supplemental financial measure by our management for reasons similar to those stated in the previous explanation of EBITDA.

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Liquidity and Capital Resources

We have historically satisfied our working capital requirements and funded our capital expenditures, investments and debt service obligations with cash generated from operations, cash provided by the issuance of debt or equity, borrowings under credit and securitization facilities and other financing transactions.

We believe that existing cash balances, future cash flows from operations and investments, borrowings under credit facilities and cash provided from the issuance of debt or equity will be sufficient to meet our working capital requirements, capital expenditures and additional investments, debt payments, commitments and distribution payments.

Nevertheless, our ability to satisfy our working capital requirements, to fund planned capital expenditures, to service our debt obligations or to pay distributions will depend upon our future operating performance and access to and cost of financing sources, which will be affected by prevailing economic conditions generally, and in both the coal and oil & gas industries specifically, as well as other financial and business factors, some of which are beyond our control, including the COVID-19 pandemic.

We have historically satisfied our working capital requirements and funded our capital expenditures, investments, contractual obligations and debt service obligations with cash generated from operations, cash provided by the issuance of debt or equity, borrowings under credit and securitization facilities and other financing transactions.

Nevertheless, our ability to satisfy our working capital requirements, to satisfy our contractual obligations, to fund planned capital expenditures, to service our debt obligations or to pay distributions will depend upon our future operating performance and access to and cost of financing sources, which will be affected by prevailing economic conditions generally, and in both the coal and oil & gas industries specifically, as well as other financial and business factors, some of which are beyond our control, including the COVID-19 pandemic.

Based on our recent operating cash flow results, current cash position, anticipated future cash flows and sources of financing that we expect to have available, we anticipate remaining in compliance with the covenants of the Credit Agreement and expect to have sufficient liquidity to fund our operations and growth strategies.

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Risk Factors."

In responding to weak market conditions, lower commodity prices, and the lockdown initiated in the first quarter of 2020 to certain areas of the global economy due to the COVID-19 pandemic, the Partnership took numerous actions to optimize cash flows and preserve liquidity by reducing capital expenditures, working capital, costs and expenses, including adjusting its corporate support structure to better align with current operating levels.

We have also benefited from certain provisions of the Coronavirus Aid Relief and Economic Security Act of 2020 which modestly increased our short-term liquidity.

Additional actions to enhance our liquidity include our Board of Directors' decisions to suspend cash distributions beginning with the quarter ended March 31, 2020 and continuing through the quarter ended December 31, 2020.

We have also strengthened our liquidity by entering into a $537.75 million (reducing to $459.5 million on May 23, 2021) revolving credit facility with a termination date of March 9, 2024, replacing the $494.75 million revolving credit facility that was set to expire on May 23, 2021.

On June 5, 2020, we entered into a $14.7 million equipment financing arrangement which provides for forty-eight monthly payments with an implicit interest rate of 6.1%, maturing on June 5, 2024.

In addition, in January 2021, we extended the term of the Securitization Facility to January 2022 and reduced the borrowing availability under the facility to $60.0 million from $100 million.

We have further enhanced our liquidity by reducing our total debt by $185.5 million during the year ended December 31, 2020.

On October 13, 2021, AR Midland acquired approximately 1,480 oil & gas net royalty acres in the Delaware Basin from Boulders for a purchase price of $31.0 million in the Boulders Acquisition.

This acquisition enhances our ownership position in the Permian Basin and furthers our business strategy to grow our Oil & Gas Royalties segment through accretive acquisitions.

Following the Boulders Acquisition, we hold approximately 57,000 net royalty acres in premier oil & gas basins including our investment in AllDale III.

For more information, please read "Item 8.

Financial Statement and Supplemental Data—Note 3 – Acquisitions".

In May 2018, the Board of Directors approved the establishment of a unit repurchase program authorizing us to repurchase up to $100 million of ARLP common units.

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for more information on the unit repurchase program.

Mine Development Project

In 2018, we began development of MC Mining's Excel Mine No.

5 which continued through 2019 and into 2020.

In July 2020, the Excel Mine No.

5 began production.

We expect the Excel Mine No.

5 will enable us to access an additional 15 million tons of coal reserves with an expected mine life of approximately 12 years assuming production levels similar to MC Mining's former Excel Mine No.

Cash provided by operating activities was $425.2 million for 2021 compared to $400.6 million for 2020.

The decrease in cash provided by operating activities was primarily due to a net loss in 2020 as compared to net income in 2019 adjusted for changes from certain non-cash items discussed above such as the acquisition gain and impairments.

The decrease in net income was partially offset by a favorable working capital changes primarily related to trade receivables and inventories.

The increase in cash provided by operating activities was primarily due to an increase in net income adjusted for non-cash items and favorable working capital changes primarily related to accounts payable and accrued payroll and related benefits, partially offset by unfavorable working capital changes related trade receivables, inventories and accrued taxes other than income taxes.

Net cash used in investing activities was $142.7 million for 2021 compared to $125.1 million for 2020.

The decrease in cash used in investing activities was primarily attributable to the AllDale and Wing Acquisitions in 2019 and decreased capital expenditures for mine infrastructure and equipment at various mines in 2020.

The decreased net cash used compared to 2019 was partially offset by cash received from the redemption of our Kodiak equity securities in 2019.

The increase in cash used in investing activities was primarily attributable Boulders Acquisition in 2021, partially offset by an increase in accounts payable and certain other accruals related to mine infrastructure, equipment and mining operations at various mines during 2021.

Net cash used in financing activities was $215.7 million for 2021 compared to $256.4 million for 2020.

The increase in cash used in financing activities was primarily attributable to increase in payments on equipment financings and lower net proceeds from borrowings under the revolving credit facility.

These 2020 increases in cash used were partially offset by proceeds received for equipment financings and reduced distributions paid to unitholders in 2020.

Contractual Obligations

We have various commitments primarily related to long-term debt, including finance and operating leases, obligations for estimated future asset retirement obligations costs, workers' compensation and pneumoconiosis, capital projects and pension funding.

We expect to fund these commitments with existing cash balances, future cash flows from operations and investments as well as cash provided from borrowings of debt or issuance of equity.

The following table provides details regarding our contractual cash obligations as of December 31, 2020:

(in thousands)

Long-term debt

Future interest obligations (1)

Operating leases

Finance leases (2)

Purchase obligations for capital projects

Reclamation obligations (3)

Workers' compensation and pneumoconiosis benefit (3)

Pension benefit (3)

(1) Interest on variable-rate, long-term debt was calculated using rates effective at December 31, 2020 for the remaining term of outstanding borrowings.

(2) Includes amounts classified as interest.

(3) Future commitments for reclamation obligations, workers' compensation and pneumoconiosis and pension are shown at undiscounted amounts.

These obligations are primarily statutory, not contractual.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements.

These arrangements include coal reserve leases, indemnifications, transportation obligations and financial instruments with off-balance sheet risk, such as bank letters of credit and surety bonds.

Liabilities related to these arrangements are not reflected in our consolidated

balance sheets, and we do not expect these off-balance sheet arrangements to have any material adverse effects on our financial condition, results of operations or cash flows.

The decrease in cash used in financing activities was primarily attributable to reduced borrowings and payments on the revolving credit

facility and reduced debt issuance costs in 2021, partially offset by increased payments and reduced borrowings on the securitization facility compared to 2020.

Cash Requirements

We currently estimate our 2022 annual cash requirements, including capital expenditures, scheduled payments on long-term debt, lease obligations, asset retirement obligation costs and workers' compensation and pneumoconiosis, to be in a range of $380.0 million to $400.0 million.

Management anticipates having sufficient cash flow to meet 2022 cash requirements with our December 31, 2021 cash and cash equivalents of $122.4 million and cash flows from operations, or borrowings under revolving credit and securitization facilities if necessary.

We currently project average estimated annual maintenance capital expenditures over the next five years of approximately $5.41 per ton produced.

For additional information on our future cash requirements other than capital expenditures, please see "Item 8.

Financial Statements and Supplementary Data—Note 8 – Long-Term Debt,"

"—Note 9 – Leases,"

"—Note 16 – Employee Benefit Plans,"

"—Note 19 – Asset Retirement Obligations,"

"—Note 20 – Accrued Workers' Compensation and Pneumoconiosis Benefits"

and "—Note 22 – Commitments and Contingencies."

We will continue to have significant cash requirements over the long term, which may require us to incur debt or seek additional equity capital.

The availability and cost of additional capital will depend upon prevailing market conditions, the market price of our common units and several other factors over which we have limited control, as well as our financial condition and results of operations.

We use a combination of surety bonds and letters of credit to secure our financial obligations for reclamation, workers' compensation and other obligations as follows as of December 31, 2021:

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Letters of credit

Capital Expenditures

Capital expenditures decreased to $121.1 million in 2020 compared to $305.9 million in 2019.

See our discussion of "Cash Flows"

above concerning the decrease in capital expenditures.

We currently project average estimated annual maintenance capital expenditures over the next five years of approximately $4.90 per ton produced.

Our anticipated total capital expenditures, including maintenance capital expenditures, for 2021 are estimated in a range of $120.0 million to $125.0 million.

Management anticipates funding 2021 capital requirements with our December 31, 2020 cash and cash equivalents of $55.6 million, cash flows from operations and investments, borrowings under revolving credit and securitization facilities and cash provided from the issuance of debt or equity.

We will continue to have significant capital requirements over the long term, which may require us to incur debt or seek additional equity capital.

Effective October 1, 2020, we renewed our annual property and casualty insurance program.

Effective December 1, 2021, we renewed our annual property and casualty insurance program.

Our property insurance was procured from our wholly owned captive insurance company, Wildcat Insurance.

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Debt Obligations

Credit Facility.

On March 9, 2020, our Intermediate Partnership entered into a Fifth Amended and Restated Credit Agreement (the "Credit Agreement") with various financial institutions.

The Credit Agreement provides for a $537.75 million revolving credit facility, reducing to $459.5 million on May 23, 2021, including a sublimit of $125 million for the issuance of letters of credit and a sublimit of $15.0 million for swingline borrowings (the "Revolving Credit Facility"), with a termination date of March 9, 2024.

The Credit Facility replaced the $494.75 million revolving credit facility extended to the Intermediate Partnership under its Fourth Amended and Restated Credit Agreement, dated as of January 27, 2017, by various banks and other lenders that would have expired on May 23, 2021.

Concurrently with the entry into the Credit Agreement, we reorganized the entities holding our oil & gas interests such that Alliance Royalty, LLC became a direct wholly owned subsidiary of Alliance Minerals.

We incurred debt issuance costs in 2020 of $5.8 million in connection with the Credit Agreement.

These debt issuance costs are deferred and amortized as a component of interest expense over the term of the Revolving Credit Facility.

The Credit Agreement is guaranteed by certain of our Intermediate Partnership's material direct and indirect subsidiaries (the "Restricted Subsidiaries") and is secured by substantially all of the assets of the Restricted Subsidiaries.

The Credit Agreement is also guaranteed by Alliance Minerals but the oil and gas minerals assets of Alliance Minerals and its direct and indirect subsidiaries (collectively with Alliance Minerals, the "Unrestricted Subsidiaries") are not collateral under the Credit Agreement.

Borrowings under the Revolving Credit Facility bear interest, at our option, at either (i) the Base Rate at the greater of three benchmarks or (ii) a Eurodollar Rate, plus margins for (i) or (ii), as applicable, that fluctuate depending upon the ratio of Consolidated Debt to Consolidated Cash Flow (each as defined in the Credit Agreement).

The Eurodollar Rate, with applicable margin, under the Revolving Credit Facility was 3.01% as of December 31, 2020.

At December 31, 2020, we had $21.8 million of letters of credit outstanding with $428.5 million available for borrowing under the Revolving Credit Facility.

We incur an annual commitment fee of 0.35% on the undrawn portion of the Revolving Credit Facility.

We utilize the Revolving Credit Facility, as appropriate, for working capital requirements, capital expenditures and investments, scheduled debt payments and distribution payments.

The Credit Agreement contains various restrictions affecting the Intermediate Partnership and its Restricted Subsidiaries including, among other things, restrictions on incurrence of additional indebtedness and liens, sale of assets, investments, mergers and consolidations and transactions with affiliates, including transactions with Unrestricted Subsidiaries.

In each case, these restrictions are subject to various exceptions.

In addition, the payment of cash distributions is restricted if such payment would result in a fixed charge coverage ratio of less than 1.0 to 1.0 (as defined in the Credit Agreement) for the four most recently ended fiscal quarters.

The Credit Agreement requires the Intermediate Partnership to maintain (a) a debt to cash flow ratio of not more than 2.5 to 1.0, (b) a cash flow to interest expense ratio of not less than 3.0 to 1.0 and (c) a first lien debt to cash flow ratio of not more than 1.5 to 1.0, in each case, during the four most recently ended fiscal quarters.

The debt to cash flow ratio, cash flow to interest expense ratio and first lien debt to cash flow ratio were 1.53 to 1.0, 8.45 to 1.0 and 0.52 to 1.0, respectively, for the trailing twelve months ended December 31, 2020.

We remained in compliance with the covenants of the Credit Agreement as of December 31, 2020 and anticipate remaining in compliance with the covenants.

Net restricted assets, as defined by the Securities and Exchange Commission, refers to the amount of our consolidated subsidiaries’ net assets for which the ability to transfer funds to ARLP in the form of cash dividends, loans, advances, or transfers is restricted.

As a result of the restrictions contained in the Credit Agreement and our current compliance ratios, the amount of our net restricted assets at December 31, 2020, was $240.8 million.

Senior Notes.

On April 24, 2017, the Intermediate Partnership and Alliance Finance, issued an aggregate principal amount of $400.0 million of senior unsecured notes due 2025 ("Senior Notes") in a private placement to qualified institutional buyers.

The Senior Notes have a term of eight years, maturing on May 1, 2025 (the "Term") and accrue interest at an annual rate of 7.5%.

Interest is payable semi-annually in arrears on each May 1 and November 1.

The indenture governing the Senior Notes contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of distributions or similar restricted payments, undertaking transactions with affiliates and limitations on asset sales.

The issuers of the Senior Notes may redeem all or a part of the notes at any time at redemption prices set forth in the indenture governing the Senior Notes.

Accounts Receivable Securitization.

On December 5, 2014, certain direct and indirect wholly owned subsidiaries of our Intermediate Partnership entered into a $100.0 million accounts receivable securitization facility ("Securitization Facility").

Under the Securitization Facility, certain subsidiaries sell certain trade receivables on an ongoing basis to our Intermediate Partnership, which then sells the trade receivables to AROP Funding, a wholly owned bankruptcy-remote special purpose subsidiary of our Intermediate Partnership, which in turn borrows on a revolving basis up to $100.0 million secured by the trade receivables.

After the sale, Alliance Coal, as servicer of the assets, collects the receivables on behalf of AROP Funding.

The Securitization Facility bears interest based on a Eurodollar Rate.

The agreement governing the Securitization Facility contains customary terms and conditions, including limitations with regards to certain customer credit ratings.

In January 2021, we extended the term of the Securitization Facility to January 2022 and reduced the borrowing availability under the facility to $60.0 million.

The Securitization Facility was previously scheduled to mature in January 2021.

At December 31, 2020, we had a $55.9 million outstanding balance under the Securitization Facility.

May 2019 Equipment Financing .

On May 17, 2019, the Intermediate Partnership entered into an equipment financing arrangement accounted for as debt, wherein the Intermediate Partnership received $10.0 million in exchange for conveying its interest in certain equipment owned indirectly by the Intermediate Partnership and entering into a master lease agreement for that equipment (the "May 2019 Equipment Financing").

The May 2019 Equipment Financing contains

customary terms and events of default and provides for thirty-six monthly payments with an implicit interest rate of 6.25%, maturing on May 1, 2022.

Upon maturity, the equipment will revert back to the Intermediate Partnership.

November 2019 Equipment Financing .

On November 6, 2019, the Intermediate Partnership entered into an equipment financing arrangement accounted for as debt, wherein the Intermediate Partnership received $53.1 million in exchange for conveying its interest in certain equipment owned indirectly by the Intermediate Partnership and entering into a master lease agreement for that equipment (the "November 2019 Equipment Financing").

The November 2019 Equipment Financing contains customary terms and events of default and an implicit interest rate of 4.75%, providing for a four year term with forty-seven monthly payments of $1.0 million and a balloon payment of $11.6 million upon maturity on November 6, 2023.

At maturity, the equipment will revert back to the Intermediate Partnership.

June 2020 Equipment Financing .

On June 5, 2020, the Intermediate Partnership entered into an equipment financing arrangement accounted for as debt, wherein the Intermediate Partnership received $14.7 million in exchange for conveying its interest in certain equipment owned indirectly by the Intermediate Partnership and entering into a master lease agreement for that equipment (the "June 2020 Equipment Financing").

The June 2020 Equipment Financing contains customary terms and events of default and provides for forty-eight monthly payments with an implicit interest rate of 6.1%, maturing on June 5, 2024.

Upon maturity, the equipment will revert back to the Intermediate Partnership.

We also have an agreement with a bank to provide additional letters of credit in an amount of $5.0 million to maintain surety bonds to secure certain asset retirement obligations and our obligations for workers' compensation benefits.

At December 31, 2020, we had $5.0 million in letters of credit outstanding under this agreement.

See "Item 8.

Financial Statements and Supplementary Data—Note 8 – Long-Term Debt"

for a discussion of our debt obligations.

Critical Accounting Policies and Estimates

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Actual results may differ from these estimates.

We have provided a description of all significant accounting policies in the notes to our consolidated financial statements.

We have provided a description of all

significant accounting policies in the notes to our consolidated financial statements.

The following critical accounting policies are materially impacted by judgments, assumptions and estimates used in the preparation of our consolidated financial statements:

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perpetual growth rate for periods beyond the long range financial forecast period.

At December 31, 2019, we had $136.4 million of goodwill, of which $132.0 million was associated with the reporting unit representing our Hamilton mine.

The goodwill associated with our Hamilton mine was recorded in conjunction with our acquisition of the Hamilton mine on July 31, 2015.

During the first quarter of 2020, we assessed certain events and changes in circumstances, including a) adverse industry and market developments, including the impact of the COVID-19 pandemic, b) our response to these developments, including temporarily ceasing production at several mines, including Hamilton and c) our actual performance during the quarter.

After consideration of these events and changes in circumstances, we performed an interim test of the goodwill associated with the Hamilton reporting unit comparing Hamilton's carrying amount to its fair value.

We estimated the fair value of the Hamilton reporting unit using a discounted cash flow model.

During the first quarter of 2020, we considered whether an interim test of our consolidated goodwill of $136.4 million was necessary.

Our consolidated goodwill included $132.0 million recorded in conjunction with our acquisition of the Hamilton mine on July 31, 2015.

We assessed certain events and changes in circumstances, including a) adverse industry and market developments, including the impact of the COVID-19 pandemic, b) our response to these developments, including temporarily ceasing production at several mines, including our Hamilton mine and c) our actual performance during the quarter.

After consideration of these events and changes in circumstances, we performed an interim test of the goodwill associated with Hamilton comparing Hamilton's carrying amount to its fair value.

We estimated the fair value of Hamilton using a discounted cash flow model.

The assumptions used in the discounted cash flow model considered market conditions at the time of the assessment and our estimate of the mine's performance in future years based on the information available to us.

The fair value of the Hamilton reporting unit was determined to be below its carrying amount (including goodwill) by more than the recorded balance of goodwill associated with the reporting unit.

Accordingly, we recognized an impairment charge of $132.0 million consisting of the total carrying amount of goodwill allocated to the Hamilton reporting unit.

The fair value of Hamilton was determined to be below its carrying amount (including goodwill) by more than the recorded balance of goodwill associated with the mine.

Accordingly, we recognized an impairment charge of $132.0 million consisting of the total carrying amount of goodwill associated with Hamilton.

This impairment charge reduced our consolidated goodwill balance to $4.4 million.

During the first quarter of 2020 and as part of our annual impairment evaluation on November 30, 2020, we also performed tests on our goodwill balance associated with our MAC reporting unit using a discounted cash flow model and concluded no impairment was necessary.

During the first quarter of 2020, we also performed tests on our goodwill balance associated with MAC using a discounted cash flow model and concluded no impairment was necessary.

There were no impairments of goodwill during 2021 or 2019.

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Significant unfavorable changes in the estimated future commodity prices could result in an impairment of our oil & gas mineral interests.

There were no impairments of our oil & gas mineral interests during 2020.

Workers ' Compensation and Pneumoconiosis (Black Lung) Benefits

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for additional discussion.

We had accrued liabilities for workers' compensation of $54.7 million and $53.4 million for these costs at December 31, 2020 and 2019, respectively.

We had accrued liabilities

for workers' compensation of $53.4 million and $54.7 million for these costs at December 31, 2021 and 2020, respectively.

A one-percentage-point reduction in the discount rate would have increased operating expense by approximately $4.1 million at December 31, 2021.

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The fair value of impaired assets is typically determined based on various factors, including the present values of expected future cash flows using a risk adjusted discount rate, the marketability of coal properties and the estimated fair value of assets that could be sold or used at other operations.

We recorded asset impairments of $25.0 million, $15.2 million and $40.5 million in 2020, 2019 and 2018, respectively.

We recorded asset

impairments of $25.0 million and $15.2 million 2020 and 2019, respectively.

There were no asset impairments during 2021.

See "Item 8.

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On at least an annual basis, we review our entire asset retirement obligation liability and make necessary adjustments for permit changes approved by state authorities, changes in the timing of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience.

Adjustments to the liability associated with these assumptions resulted in a decrease of $11.9 million for the year ended December 31, 2020.

There were no material adjustments to the liability associated with these assumptions for the year ended December 31, 2021.

Adjustments to the liability associated with these assumptions resulted in a decrease of $11.9 million for the year ended December 31, 2020.

While the precise amount of these future costs cannot be determined with certainty, we have estimated the costs and timing of future asset retirement obligations escalated for inflation, then discounted and recorded at the present value of those estimates.

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Shelf Registration Statement

In February 2018, we filed with the SEC a universal shelf registration statement allowing us to issue from time to time an indeterminate amount of debt or equity securities ("2018 Registration Statement").

At February 23, 2021, we had not utilized any amounts available under the 2018 Registration Statement.

In February 2018, we filed with the SEC a universal shelf registration statement which allowed us to issue from time to time an indeterminate amount of debt or equity securities ("2018 Registration Statement").

The 2018 Registration Statement expired in February 2021.

We did not utilize any amounts available under the 2018 Registration Statement.

We currently intend to file with the SEC a new universal shelf registration statement.

Related – Party Transactions

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Please see "Item 8.

Financial Statements and Supplementary Data—Note 19 – Asset Retirement Obligations"

Financial Statements

and Supplementary Data—Note 19 – Asset Retirement Obligations"

and "—Note 20 – Accrued Workers' Compensation and Pneumoconiosis Benefits."

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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 7. Management’s Discussion and Analysis