What changed in this filing

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Item 7. Management’s Discussion and Analysis

2023-02-24 compared with 2022-02-25 · 164 added, 318 removed, 349 unchanged (58% of the section changed)

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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.

In addition, we continue to position ourselves as a reliable energy provider for the future as we pursue opportunities that support the advancement of energy and related infrastructure.

We intend to pursue strategic investments that leverage our core competencies and relationships with electric utilities, industrial customers, and federal and state governments.

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.

The oil & gas mineral interests we own are in premier oil & gas producing regions of the United States, primarily in the Permian (Delaware and Midland), Anadarko (SCOOP/STACK) and Williston (Bakken) basins.

Our investments in energy and infrastructure consist of a variety of businesses such as electric vehicle charging stations and electric motors, in addition to private equity investments in renewable energy, the electrification of our economy or the efficient use of energy.

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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As of December 31, 2022, we had approximately 580.7 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.

Substantially, all of our measured, indicated and inferred coal mineral resources and 464.8 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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in our Annual Report on Form 10-K for the year ended December 31, 2022 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.

Based on market expectations, we classify low-sulfur coal as coal with a sulfur content of less than 1.5%, medium-sulfur coal as coal with a sulfur content of 1.5% to 3%, and high-sulfur coal as coal with a sulfur content of greater than 3%.

The Btu content of our coal ranges from 11,450 to 13,200.

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

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 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.

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.

We currently own minerals interests in approximately 61,400 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 mineral interests for lease to operators and generate royalty income from leasing and development of those mineral interests.

As of December 31, 2022, we had 20,596 MBOE of proved oil & gas reserves.

On September 9, 2022, we acquired approximately 394 oil & gas net royalty acres in the Delaware Basin from Belvedere.

On October 26, 2022, we acquired approximately 3,928 oil & gas net royalty acres in the Midland and Delaware Basins from Jase.

See "Item 8.

Financial Statements and Supplementary Data—Note 3 – Acquisitions"

for more information about the Belvedere and Jase Acquisitions.

On January 27, 2023, we entered into a one-year collaborative agreement with a third party effective January 1, 2023, committing up to $35.0 million for the acquisition of oil & gas mineral interests in the Midland and Delaware basins.

On February 22, 2023, we acquired approximately 2,682 oil & gas net royalty acres in the Delaware Basin from JC Resources, a related-party entity owned by Mr.

We have invested $66.1 million in the advancement of energy and related infrastructure opportunities including Francis, Infinitum, and NGP ETP IV, and as of December 31, 2022 have a remaining commitment of $20.9 million to

See "Item 8.

Financial Statements and Supplementary Data – Note 14 – Investments"

for additional information on Francis, Infinitum and NGP ETP IV.

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, by the availability or reliability of transportation for coal shipments and by other supply chain shortage issues or disruptions.

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

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Risk Factors".

Our principal expenses related to the production of coal are labor and benefits, equipment, materials and supplies, maintenance, royalties and excise taxes in addition to capital required to maintain our current levels of production.

Our principal expenses related to the production of coal are labor and benefits, equipment, materials and supplies, maintenance, royalties and excise taxes in addition to the capital required to maintain our current levels of production.

We employ a totally union-free workforce.

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● 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;

● extending the lives of our current mining operations through the 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 in other industries inside and outside of the MLP sector;

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

● continuing to identify and make strategic investments in the advancement of energy and related infrastructure opportunities to leverage our core competencies.

As of December 31, 2022, we had four reportable segments:

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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 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.

Our Oil & Gas Royalties reportable segment includes our oil & gas 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 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.

● 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.

Financial Statements and Supplementary Data — Note 3 – Acquisitions"

— Note 13 – Investments"

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.

● The Illinois Basin Coal Operations reportable segment includes (a) the Gibson County Coal mining complex, (b) the Warrior mining complex, (c) the River View mining complex and (d) the Hamilton mining complex.

The segment also includes our Mt.

Vernon coal-loading terminal in Indiana which operates on the Ohio River, Mid-America Carbonates, LLC ("MAC") and other support services, and our non-operating mining complexes.

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

● The Oil & Gas Royalties reportable segment includes oil & gas mineral interests held by AR Midland and AllDale I & II and includes Alliance Minerals' equity method investment in AllDale III.

● The 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"

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

● Other, Corporate and Elimination includes marketing and administrative activities, the Matrix Group, our investments in Francis, Infinitum and NGP ETP IV (see "Item 8.

Financial Statements and Supplementary Data—Note 14 – Investments"), Wildcat Insurance, which assists the ARLP Partnership with its insurance requirements, AROP Funding, LLC and Alliance Resource Finance Corporation (both discussed in "Item 8.

Financial Statements and Supplementary Data—Note 8 – Long-Term Debt") and other miscellaneous activities.

The eliminations included in Other, Corporate and Elimination primarily represent the intercompany coal royalty transactions described above between our Coal Royalties reportable segment and our coal operations' mines.

How We Evaluate Our Performance

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EBITDA is used as a supplemental financial measure by our 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.

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 Generally Accepted Accounting Principles ("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.

Segment Adjusted EBITDA.

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

Management therefore is able to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments.

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2022 Compared with 2021

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.

Total revenues increased 53.3% to a record $2.41 billion in 2022 compared to $1.57 billion in 2021 primarily due to substantial increases in prices and volumes from coal operations and royalties and oil & gas royalties.

Total operating expenses increased to $1.75 billion in 2022 compared to $1.35 billion in 2021 due primarily to increased coal sales volumes and ongoing inflationary cost pressures.

Higher revenues, partially offset by increased total operating expenses and income tax expense, led to significantly higher net income attributable to ARLP, which rose 224.0% to a record $577.2 million for 2022, or $4.39 per basic and diluted limited partner unit, compared to $178.2 million, or $1.36 per basic and diluted limited partner unit, for 2021.

Year Ended December 31,

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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.'"

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

(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.

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Coal sales increased $715.3 million or 51.6% to $2.10 billion for 2022 from $1.39 billion for 2021.

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.

The increase was attributable to a price variance of $572.6 million due to higher average coal sales prices and a volume variance

of $142.7 million resulting from increased tons sold.

Coal sales price realizations increased by 37.4% in 2022 to a record $59.07 per ton sold, compared to $42.98 per ton sold during 2021, due to favorable market conditions.

Improved coal demand in both the domestic and export markets during 2022 drove coal sales volumes higher by 10.3% to 35.6 million tons sold compared to 32.3 million tons sold in 2021.

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:

Segment Adjusted EBITDA Expense for our coal operations increased 34.0% to $1.31 billion, as a result of higher coal sales volumes and inflationary cost pressures.

On a per ton basis, Segment Adjusted EBITDA Expense for our coal operations increased 21.5% to $36.73 per ton sold in 2022 compared to $30.24 per ton in 2021, primarily due to certain cost increases, which are discussed below by category:

● Labor and benefit expenses per ton produced, excluding workers' compensation, increased 14.9% to $10.95 per ton in 2022 from $9.53 per ton in 2021.

The increase of $1.42 per ton was primarily due to higher labor costs at several mines.

● Material and supplies expenses per ton produced increased 34.3% to $14.10 per ton in 2022 from $10.50 per ton in 2021.

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.

The increase of $3.60 per ton produced primarily reflects inflationary cost pressures including increases of $1.11 per ton for roof support, $0.47 per ton for ventilation related expenses, $0.47 per ton for power and fuel, $0.39 per ton for contract labor used in the mining process, $0.37 per ton for various preparation plant expenses and $0.26 per ton for environmental and reclamation expenses other than longwall subsidence.

● Maintenance expenses per ton produced increased 31.4% to $3.64 per ton in 2022 from $2.77 per ton in 2021.

The increase of $0.87 per ton produced was primarily as a result of inflationary cost pressures.

● Production taxes and royalty expenses per ton incurred as a percentage of coal sales prices and volumes increased $0.68 per produced ton sold in 2022 compared to 2021 primarily as a result of higher price realizations, partially offset by a temporary decrease in the federal black lung excise tax, from January 1, 2022 to September 30, 2022, a favorable mix of tons sold mined in states with severance taxes and decreased excise taxes per ton resulting from a greater mix of export shipments .

Oil & gas royalties .

Oil & gas royalty revenues increased to $138.4 million in 2022 compared to $75.0 million for 2021.

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.

The increase of $63.4 million was primarily due to significantly higher sales price realizations per BOE and volumes in 2022.

Other revenues .

Other revenues principally comprised Matrix Design sales, Mt.

Vernon transloading revenues and other miscellaneous sales and revenue activities.

Other revenues increased to $52.0 million in 2022 from $38.5 million in 2021.

The increase of $13.5 million was primarily due to increased sales of mining technology products by our Matrix Design subsidiary.

Income tax expense.

Income tax expense increased to $54.0 million for 2022 compared to $0.4 million for 2021 as a result of Alliance Minerals' election during 2022 to be treated as a taxable entity for federal and state income tax purposes.

We recognized a one-time non-cash income tax charge of $37.3 million and income tax expense of $17.5 million during 2022 related to Alliance Minerals.

Please read "Item 8.

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

Financial Statements and Supplementary Data—Note 9 – Income Taxes."

Transportation revenues and expenses .

Transportation revenues and expenses were $113.9 million and $69.6 million for 2022 and 2021, 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.

The increase of $44.3 million was primarily attributable to increased average third-party transportation rates in 2022 and increased coal shipments 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.

Our 2022 Segment Adjusted EBITDA increased $471.3 million, or 85.8%, to $1.02 billion from 2021 Segment Adjusted EBITDA of $549.3 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:

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Intercompany coal royalties

(1) Percentage change not meaningful.

(1) 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)."

(2) For definitions of Segment Adjusted EBITDA and Segment Adjusted EBITDA Expense and related reconciliations to their respective comparable GAAP financial measures, please see below under "—Reconciliation of GAAP 'net income' to non-GAAP 'Segment Adjusted EBITDA' and reconciliation of GAAP 'Operating Expenses' to non-GAAP 'Segment Adjusted EBITDA Expense.'"

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

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Illinois Basin Coal Operations – Segment Adjusted EBITDA increased to $420.7 million in 2022 from $265.3 million in 2021.

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."

The increase of $155.4 million was primarily attributable to higher coal sales, which increased 39.6% to $1.22 billion in 2022 from $873.9 million in 2021, partially offset by increased operating expenses.

The increase in coal sales reflects higher coal sales price per ton, which increased by 28.9% compared to 2021 due to increased domestic prices and significantly higher export prices and increased tons sold, which rose 8.3% in 2022 as a result of increased sales volumes primarily at our Gibson South mine.

Segment Adjusted EBITDA Expense increased 31.4% to $806.1 million in 2022 from $613.3 million in 2021 primarily as a result of increased sales volumes and higher expenses per ton.

Segment Adjusted EBITDA Expense per ton increased $5.88 per ton sold to $33.43 from $27.55 per ton sold in 2021 primarily as a result of inflationary pressures on numerous expense items, including labor-related expenses and supply and maintenance costs, increased sales-related expenses due to higher price realizations, reduced recoveries across the region and lost production due to an unexpected outage caused by a thermal event which lasted approximately four weeks in addition to increased longwall move days at our Hamilton mine during 2022.

There were no injuries and no damages to equipment as a result of the thermal event at Hamilton, and mining operations returned to normal production levels in December 2022.

Appalachia Coal Operations – Segment Adjusted EBITDA increased 147.0% to $426.4 million for 2022 from $172.6 million in 2021.

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."

The increase of $253.8 million was primarily attributable to higher coal sales, which increased 72.0% to $882.3 million in 2022 from $513.0 million in 2021, due to increased prices and volumes.

Coal sales prices increased by 49.9% compared to 2021 primarily due to substantially higher export price realizations and increased domestic pricing in the region.

Coal sales volumes increased 14.7% compared to 2021 as a result of higher sales volumes from our Tunnel Ridge and MC Mining operations.

Segment Adjusted EBITDA Expense increased 34.8% to $464.0 million in 2022 from $344.3 million in 2021 due to increased sales volumes and per ton expenses.

Segment Adjusted EBITDA Expense per ton increased 17.4% to $40.42 compared to $34.42 per ton sold in 2021, as a result of inflationary pressures on numerous expense items, including labor-related expenses and supply and maintenance costs, increased sales-related expenses due to higher price realizations, reduced recoveries at our Mettiki and MC Mining operations and increased longwall move days at our Tunnel Ridge and Mettiki mines during 2022.

Oil & Gas Royalties – Segment Adjusted EBITDA increased to $131.2 million for 2022 from $68.8 million in 2021.

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

The increase of $62.4 million was primarily due to higher sales price realizations, which increased 39.1% to $62.70 per BOE, and increased volumes in 2022.

Volumes increased by 32.8% to 2.2 million BOE sold in 2022 compared to 1.7 million BOE sold in 2021 as a result of increased drilling and completion activities and additional volumes from oil & gas mineral interest acquisitions completed during 2022.

Coal Royalties – Segment Adjusted EBITDA increased 16.9% to $38.8 million for 2022 from $33.2 million in 2021.

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.

The increase of $5.6 million was a result of increased royalty tons sold and higher average royalty rates per ton.

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.

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

(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.

The decrease was attributable to a volume variance of $496.9 million resulting from decreased tons sold and a price variance of $33.3 million due to lower average coal sales prices.

Tons sold declined 28.2% to 28.2 million tons in 2020, due to reduced shipments to domestic utilities and international markets.

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 Coal Operations region, in response to weak market conditions during 2020.

Coal - Segment Adjusted EBITDA Expense .

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 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.

Cost per ton in 2020 also benefited from improved recoveries at several mines in both regions offset in part by reduced unit shifts from the curtailment.

Our costs per ton were impacted by the following cost variances as discussed by category:

● Material and supplies expenses per ton produced decreased 8.6% to $10.01 per ton in 2020 from $10.95 per ton in 2019.

The decrease of $0.94 per ton produced resulted primarily from production mix benefits and improved recoveries previously mentioned, related decreases of $0.46 per ton for roof support, $0.32 per ton for contract labor used in the mining process and $0.14 per ton for certain ventilation expenses, partially offset by an increase of $0.15 per ton for power and fuel used in the mining process .

● Maintenance expenses per ton produced decreased 13.1% to $3.12 per ton in 2020 from $3.59 per ton in 2019.

The decrease of $0.47 per ton produced was primarily due to reduced maintenance requirements as a result of production mix benefits and improved recoveries previously mentioned.

● We had no sales of outside coal purchases in 2020 compared to $23.4 million in 2019.

Thus, costs per ton in 2020 benefited as our cost of outside coal purchases are generally higher on a per ton basis than our produced coal.

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

● Labor and benefit expenses per ton produced, excluding workers' compensation, increased 8.7% to $10.75 per ton in 2020 from $9.89 per ton in 2019.

The increase of $0.86 per ton was primarily due to curtailed production, partially offset by an improved production mix and improved recoveries at certain mines all previously discussed.

● Production taxes and royalty expenses per ton incurred as a percentage of coal sales prices and volumes increased $0.53 per produced ton sold in 2020 compared to 2019 primarily as a result of a $0.60 per ton government-imposed increase in the federal black lung excise tax, effective January 1, 2020 and an unfavorable state production mix increasing severance taxes per ton, in addition to increased excise taxes per ton resulting from a greater mix of domestic vs.

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 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.

Other revenues decreased to $31.8 million in 2020 from $48.0 million in 2019.

The decrease of $16.2 million was primarily due to reduced sales of mining technology products by our Matrix Design subsidiary and lower coal volumes shipped through our Mt.

Vernon transloading facility.

General and administrative.

General and administrative expenses for 2020 decreased to $59.8 million compared to $73.0 million in 2019.

The decrease of $13.2 million was primarily due to incentive compensation reductions and our expense reduction initiatives.

Asset impairments.

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

Please read "Item 8.

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

of this Annual Report on Form 10-K."

Goodwill impairment.

Please read "Item 8.

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

of this Annual Report on Form 10-K.

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 Gas Service, LLC ("Kodiak") in 2019.

Acquisition gain .

We recorded a non-cash acquisition gain of $177.0 million in 2019 associated with the AllDale Acquisition to reflect the fair value of the interests in AllDale I & II we already owned at the time of the acquisition.

Transportation revenues and expenses .

Transportation revenues and expenses were $21.1 million and $99.5 million for 2020 and 2019, respectively.

The decrease of $78.4 million was largely attributable to decreased coal tonnage for which we arrange third-party transportation at certain mines primarily reflecting reduced coal shipments to international markets and a decrease in average third-party transportation rates in 2020.

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

Net income attributable to noncontrolling interest .

Net income attributable to noncontrolling interest decreased to $0.2 million in 2020 from $7.5 million in 2019 as a result of allocating $7.1 million of the acquisition gain discussed above to noncontrolling interest in 2019.

Segment Information .

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.

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

Other, Corporate and Elimination

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 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.

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.

Segment Adjusted EBITDA Expense per ton increased $0.62 per ton sold to $28.42 from $27.80 per ton sold in 2019, primarily due to reduced coal volumes and related increased fixed costs per ton offset in part by the closure of higher cost per ton operations, improved recoveries at certain mines in 2020 and reduced reclamation accruals at certain non-operating mines.

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

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.

The decrease of $151.3 million in coal sales reflects lower tons sold and price realizations.

Sales volumes decreased 15.8% in 2020 compared to 2019 due to curtailed production in the region as a result of weak coal market conditions, particularly international markets, amid the COVID-19 pandemic.

Coal sales price per ton sold in 2020 decreased 9.8% compared to 2019 primarily due to reduced metallurgical tons sold and price realizations at our Mettiki mine.

Segment Adjusted EBITDA Expense decreased 24.4% to $320.7 million in 2020 from $424.4 million in 2019 due to reduced tons sold and decreased per ton costs.

Segment Adjusted EBITDA Expense per ton decreased $4.02 per ton sold to $35.24 compared to $39.26 per ton sold in 2019.

The lower per ton expense in 2020 resulted primarily from fewer longwall move days and improved recoveries at both our Tunnel Ridge and Mettiki mines, reduced roof support expenses per ton and the absence of higher cost purchased tons sold in 2020, partially offset by curtailed production in the region during 2020 increasing fixed costs per ton.

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

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"

to GAAP "net income (loss)"

and reconciliation of non-GAAP "Segment Adjusted EBITDA Expense"

to GAAP "Operating 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.

For discussion and analysis of 2021 compared to 2020, 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, 2021, which was filed with the SEC on February 25, 2022 and amended on August 26, 2022, and is incorporated by reference herein.

Reconciliation of GAAP "net income"

to non-GAAP "Segment Adjusted EBITDA"

and reconciliation of GAAP "Operating Expenses"

to non-GAAP "Segment Adjusted EBITDA Expense"

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 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.

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.

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.

In addition, the exclusion of corporate general and administrative expenses, which are discussed above under "—Analysis of Historical Results of Operations,"

from consolidated Segment Adjusted EBITDA allows management to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments.

The following is a reconciliation of consolidated Segment Adjusted EBITDA to net income (loss), the most comparable GAAP financial measure:

In addition, the exclusion of corporate general and administrative expenses from consolidated Segment Adjusted EBITDA allows management to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments.

The following is a reconciliation of net income, the most comparable GAAP financial measure, to consolidated Segment Adjusted EBITDA:

Year Ended December 31,

(in thousands)

Consolidated Segment Adjusted EBITDA

Noncontrolling interest

Net income attributable to ARLP

General and administrative

Depreciation, depletion and amortization

Asset impairments

Goodwill impairment

Interest expense, net

Acquisition gain

Income tax (expense) benefit

Acquisition gain attributable to noncontrolling interest

Net income (loss) attributable to ARLP

Noncontrolling interest

Net income (loss)

Segment Adjusted EBITDA Expense (a non-GAAP financial measure) includes operating expenses, coal purchases and other income (expense).

Income tax expense

Consolidated Segment Adjusted EBITDA

Segment Adjusted EBITDA Expense (a non-GAAP financial measure) includes operating expenses, coal purchases and other expense (income).

Transportation expenses are excluded as these expenses are passed through to our customers and, consequently, we do not realize any gain or loss on transportation revenues.

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The exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA Expense allows management to focus solely on the evaluation of segment operating performance as it primarily relates to our operating expenses.

The following is a reconciliation of consolidated Segment Adjusted EBITDA Expense to operating expense, the most comparable GAAP financial measure:

The following is a reconciliation of operating expenses, the most comparable GAAP financial measure, to consolidated Segment Adjusted EBITDA Expense:

Year Ended December 31,

(in thousands)

Segment Adjusted EBITDA Expense

Outside coal purchases

Other income (expense)

Operating expenses (excluding depreciation, depletion and amortization)

Outside coal purchases

Other expense (income)

Segment Adjusted EBITDA Expense

Ongoing Acquisition Activities

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For more information on acquisitions, please read "Item 8.

Financial Statements and Supplementary Data—Note 3 – Acquisitions"

Financial Statements and Supplementary Data—Note 1 – Organization and Presentation,"

"—Note 3 – Acquisitions"

and "—Note 26 – Subsequent Events"

of this Annual Report on Form 10-K.

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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, contractual obligations, commitments and distribution payments.

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.

Nevertheless, our ability to satisfy our working capital requirements and additional investments, 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.

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 being in compliance with the covenants of the Credit Agreement and expect to have sufficient liquidity to fund our operations and growth strategies.

However, to the extent operating cash flow or access to and cost of financing sources are materially different than expected, future covenant compliance or liquidity may be adversely affected.

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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 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.

Oil & Gas Acquisitions — During 2022, through the Belvedere and Jase Acquisitions, we acquired approximately 4,322 oil & gas net royalty acres in the Permian Basin for an aggregate purchase price of $92.6 million.

We funded these acquisitions with cash on hand.

We plan to fund our commitment with cash on hand or cash generated from operations.

On February 22, 2023, we acquired approximately 2,682 oil & gas net royalty acres in the Delaware Basin from JC Resources, a related-party entity owned by Mr.

Craft, for $72.3 million, which was funded with cash on hand.

For additional information about acquisitions of oil & gas assets and the collaborative agreement, please see "Business — Oil & Gas Acquisitions."

New Venture Investments — During 2022, we made strategic investments in attractive opportunities that support the advancement of energy and related infrastructure, including investments of $20 million in Francis, $42 million in Infinitum and, as of December 31, 2022, $4.1 million (of a $25 million commitment) in NGP ETP IV.

For additional information about our energy and infrastructure investments, please see "Business — New Venture Investments."

Unit Repurchase Program — 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.

The program has no time limit and we may repurchase units from time to time in the open market or in other privately negotiated transactions.

The unit repurchase program authorization does not obligate us to repurchase any dollar amount or number of units.

Since inception through December 31, 2021, we have purchased units for a total of $93.5 million under the program.

Since inception through December 31, 2022, we had purchased units for a total of $93.5 million under the program.

During the year ended December 31, 2022, we did not repurchase and retire any units.

In January 2023, the Board of Directors authorized a $93.5 million increase to the unit repurchase program.

As a result, we are authorized to repurchase up to a total of $100.0 million of ARLP's limited partner common units.

Please read "Item 5.

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for more information on the unit repurchase program.

Revolving Credit Facility — On January 13, 2023, Alliance Coal entered into a Credit Agreement (the "Credit Agreement") with various financial institutions.

The Credit Agreement provides for a $425 million revolving credit facility, which includes a sublimit of $15.0 million for swingline borrowings and permits the issuance of letters of credit of up to the full amount of $425 million (the "Revolving Credit Facility"), and for a term loan in an aggregate principal amount of $75 million (the "Term Loan").

The Credit Agreement matures on March 9, 2027, at which time the aggregate outstanding principal amount of all Revolving Credit Facility advances and all Term Loan advances are required to be repaid in full.

The Credit Agreement will instead mature on January 30, 2025, if on that date our Senior Notes are still outstanding and Alliance Coal does not have liquidity of at least $200 million.

Interest is payable quarterly, with principal of the Term Loan due in quarterly installments equal to 6.25% of the original principal amount of the Term Loan beginning with the quarter ending June 30, 2023 and the balance payable at maturity.

The Revolving Credit Facility replaces the $459.5 million revolving credit facility ("Replaced Credit Facility"), which included a sublimit of $125 million for the issuance of letters of credit and a sublimit of $15.0 million for swingline borrowings, extended to the Intermediate Partnership under its Fifth Amended and Restated Credit Agreement, dated as of March 9, 2020 that would have expired on March 9, 2024.

The Credit Agreement is guaranteed by ARLP and certain of its subsidiaries, including the Intermediate Partnership and most of the direct and indirect subsidiaries of Alliance Coal (the "Subsidiary Guarantors").

The Credit Agreement also is secured by substantially all of the assets of the Subsidiary Guarantors and Alliance Coal.

For additional information on the Credit Agreement, please see "Item 8.

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

Mine Development Project — In 2022, we began development of River View's Mine No.

2 and continued in 2023.

We currently anticipate deploying capital of approximately $42.0 million in 2023 and $24.0 million in 2024 to complete the project.

We expect to fund the project with cash from operations or borrowings under our credit facilities.

We anticipate the new mine will enable us to access an additional 109.5 million clean recoverable tons of coal.

Cash provided by operating activities was $791.8 million for 2022 compared to $425.2 million for 2021.

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.

The increase in cash provided by operating activities was primarily due to an increase in net income adjusted for non-cash items, partially offset by unfavorable working capital changes primarily related to trade receivables.

Net cash used in investing activities was $403.3 million for 2022 compared to $142.7 million for 2021.

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.

The increase in cash used in investing activities was primarily attributable to an increase in capital expenditures, purchases of equity securities, payments for the Belvedere and Jase Acquisitions in 2022 and contributions to equity method investments, partially offset by payments for the Boulders Acquisition in 2021.

See "Item 8.

Financial Statements and Supplementary Data—Note 3 – Acquisitions"

for more information on the Boulders, Belvedere and Jase Acquisitions.

Net cash used in financing activities was $214.9 million for 2022 compared to $215.7 million for 2021.

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.

The decrease in cash used in financing activities was primarily attributable to reduced net borrowings and payments on equipment financings, and on the revolving credit and securitization facilities, mostly offset by increased distributions to partners.

Cash Requirements

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Letters of credit

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

Effective December 1, 2022, we renewed our property and casualty insurance program through October 1, 2023.

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

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The maximum limit in the commercial property program is $100.0 million per occurrence, excluding a $1.5 million deductible for property damage, a 75 or 90 day waiting period for underground business interruption depending on the mining complex and an additional $25.0 million overall aggregate deductible.

We have elected to retain a 10% participating interest in our commercial property insurance program.

We can make no assurances that we will not experience significant insurance claims in the future that could have a material adverse effect on our business, financial condition, results of operations and ability to purchase property insurance in the future.

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Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States.

Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States.

The preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts and disclosures in the consolidated financial statements.

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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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Financial Statements and Supplementary Data—Note 3 – Acquisitions"

for more information on the Wing and AllDale Acquisitions.

for more information on the Belvedere and Jase Acquisitions.

Assets acquired and liabilities assumed are recorded at their estimated fair values at the acquisition date.

The excess of purchase price over fair value of net assets acquired is recorded as goodwill.

The excess of purchase price over fair value of net assets acquired, if any, is recorded as goodwill.

Given the time it takes to obtain pertinent information to finalize the acquired business' balance sheet, it may be several quarters before we are able to finalize those initial fair value estimates.

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The results of operations of acquired businesses are included in the consolidated financial statements from the acquisition date.

For the Wing Acquisition, we determined a fair value for the acquired mineral interests using a weighting of both income and market approaches.

Our income approach primarily comprised of a discounted cash flow model.

The assumptions used in the discounted cash flow model included estimated production, projected cash flows, forward oil & gas prices and a risk-adjusted discount rate.

Our market approach consisted of the observation of acquisitions in the Permian Basin to determine a market price for similar mineral interests.

For the AllDale Acquisition, in addition to valuing the acquired assets and liabilities, we were required to value our previously held equity method investments in AllDale I & II just prior to the acquisition and record a gain as the fair value was determined to be higher than the carrying value of our equity method investments.

We used a discounted cash flow model to re-measure our equity method investments immediately prior to the AllDale Acquisition as well as to value the mineral interests acquired.

Assumptions used in our discounted cash flow model are similar to those discussed in the Wing Acquisition above.

For the Belvedere and Jase Acquisitions, we determined a fair value for the acquired mineral interests using an income approach consisting of discounted cash flow models.

The assumptions used in the discounted cash flow models included estimated production, projected cash flows, forward oil & gas prices and risk adjusted discount rates.

The only indefinite-lived intangible that the Partnership currently has is goodwill.

Goodwill is not amortized, but subject to annual reviews on November 30th for impairment at the reporting unit level.

Goodwill is not amortized, but subject to annual reviews for impairment at the reporting unit level.

Goodwill is assessed for impairment more frequently if events or changes in circumstances indicate that it is more likely than not that goodwill is impaired.

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Our estimate of the forward coal sales price curve and future sales volumes are critical assumptions used in our discounted cash flow analysis.

A discounted cash flow analysis requires us to make various judgmental assumptions about sales, operating margins, capital expenditures, working capital and coal sales prices.

Assumptions about sales, operating margins, capital expenditures and coal sales prices are based on our budgets, business plans, economic projections, and anticipated future cash flows.

A discounted cash flow analysis requires us to make various judgmental assumptions about sales, operating margins, capital expenditures, working capital and commodity sales prices.

Assumptions about sales, operating margins, capital expenditures and commodity sales prices are based on our budgets, business plans, economic projections, and anticipated future cash flows.

In determining the fair value of our reporting units, we are required to make significant judgments and estimates regarding the impact of anticipated economic factors on our business.

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As a result, actual performance in the near and longer-term could be different from these expectations and assumptions.

This could be caused by events such as strategic decisions made in response to economic and competitive conditions and the impact of economic factors, such as over production in coal and low prices of natural gas.

In addition, some of the inherent estimates and assumptions used in determining fair value of the reporting units are outside the control of management, including interest rates, cost of capital and our credit ratings.

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for additional discussion.

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.

We had accrued liabilities for workers' compensation of $49.5 million and $53.4 million for these costs at December 31, 2022 and 2021, respectively.

A one-percentage-point reduction in the discount rate would have increased operating expense by approximately $2.6 million at December 31, 2022.

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The discount rate for workers' compensation and pneumoconiosis is derived by applying the Financial Times Stock Exchange Pension Discount Curve to the projected liability payout.

Other assumptions, such as claim development patterns, mortality, disability incidence and medical costs, are based upon standard actuarial tables adjusted for our actual historical experiences whenever possible.

Other assumptions, such as claim development patterns, mortality, disability incidence and medical costs, are based on standard actuarial tables adjusted for our actual historical experiences whenever possible.

We review all actuarial assumptions periodically for reasonableness and consistency and update such factors when underlying assumptions, such as discount rates, change or when sustained changes in our historical experiences indicate a shift in our trend assumptions are warranted.

Impairment of Long-Lived Assets

In addition to oil & gas reserves discussed above in the Oil & Gas Reserve Values section, we review the carrying value of long-lived assets and certain identifiable intangibles whenever events or changes in circumstances indicate that the carrying amount may not be recoverable based upon estimated undiscounted future cash flows.

Long-lived assets and certain intangibles are not reviewed for impairment unless an impairment indicator is noted.

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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 and $15.2 million 2020 and 2019, respectively.

There were no asset impairments during 2021.

We recorded an asset impairment of $25.0 million in 2020.

See "Item 8.

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Depreciation is generally determined on a units-of-production basis and accretion is generally recognized over the life of the producing assets.

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.

estimates and productivity assumptions, to reflect current experience.

Adjustments to the liability associated with these assumptions resulted in an increase of $17.4 million for the year ended December 31, 2022.

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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In February 2022, 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 ("2022 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.

As of February 24, 2023, we had not utilized any amounts available under the 2022 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 20 – Asset Retirement Obligations"

and "—Note 21 – Accrued Workers' Compensation and Pneumoconiosis Benefits."

Any future inflationary or deflationary pressures could adversely affect the results of our operations.

For example, at times our results have been significantly impacted by price increases affecting many of the components of our operating expenses such as fuel, steel, maintenance expense and labor.

Please see "Item 1A.

For example, during 2022 our results were significantly impacted by price increases affecting many of the components of our operating expenses such as fuel, steel, maintenance expense and labor.

Please see above under "— Analysis of Historical Results of Operations"

and "Item 1A.

Risk Factors."

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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