Item 7. Management’s Discussion and Analysis
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
General
The following discussion of our financial condition and results of operations should be read in conjunction with the historical financial statements and notes thereto included in "Item 8. Financial Statements and Supplementary Data" where you can find more detailed information in "Note 1 – Organization and Presentation" and "Note 2 – Summary of Significant Accounting Policies" regarding the basis of presentation supporting the following financial information.
Executive Overview
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 (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. Our River View and Tunnel Ridge mines and Mt. Vernon transloading facility are located on the Ohio River. 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. 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. Please see "Item 1. Business—Coal Mining Operations" in our Annual Report on Form 10-K for the year ended December 31, 2022 for further discussion of our mines.
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. Craft.
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
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NGP ETP IV. 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. 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.
We are dependent on third-party operators for the exploration, development and production of our oil & gas mineral interests; therefore, the success and timing of drilling and development of our oil & gas mineral interests depend on a number of factors outside our control. Some of those factors include the operators' capital costs for drilling, development and production activities, the operators' ability to access capital, the operators' selection of counterparties for the marketing and sale of production and oil & gas prices in general, among others. The operations on the properties in which we hold oil & gas mineral interests are also subject to various governmental laws and regulations. Compliance with these laws and regulations could be burdensome or expensive for these operators and could result in the operators incurring significant liabilities, either of which could delay production and may ultimately impact the operators' ability and willingness to develop the properties in which we hold oil & gas mineral interests.
For additional information regarding some of the risks and uncertainties that affect our business and the industries in which we operate, see "Item 1A. 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 the capital required to maintain our current levels of production. We employ a totally union-free workforce. 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, 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 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 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; and
● 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: Illinois Basin Coal Operations, Appalachia Coal Operations, Oil & Gas Royalties and Coal Royalties. We also have an "all other" category referred to as Other, Corporate and Elimination. 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
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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.
● 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, 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
Our management uses a variety of financial and operational measurements to analyze our performance. Primary measurements include the following: (1) raw and saleable tons produced per unit shift; (2) coal sales price per ton; (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; (8) EBITDA; and (9) Segment Adjusted EBITDA.
Raw and Saleable Tons Produced per Unit Shift. We review raw and saleable tons produced per unit shift as part of our operational analysis to measure the productivity of our operating segments, which is significantly influenced by mining conditions and the efficiency of our preparation plants. Our discussion of mining conditions and preparation plant costs are found below under "— Analysis of Historical Results of Operations " and therefore provides implicit analysis of raw and saleable tons produced per unit shift.
Coal Sales Price per Ton. We define coal sales price per ton as total coal sales divided by tons sold. We review coal sales price per ton to evaluate marketing efforts and for market demand and trend analysis.
Oil & gas BOE sold . We monitor and analyze our BOE sales volumes from the various basins that comprise our portfolio of mineral interests. We also regularly compare projected volumes to actual volumes reported and investigate unexpected variances.
Price per BOE. We define price per BOE as total oil & gas royalties divided by BOE produced. 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.
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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. We define Segment Adjusted EBITDA Expense per ton (a non-GAAP financial measure) as the sum of operating expenses, coal purchases and other expense divided by total tons sold. We review Segment Adjusted EBITDA Expense per ton for cost trends.
EBITDA. We define EBITDA (a non-GAAP financial measure) as net income attributable to ARLP before net interest expense, income taxes and depreciation, depletion and amortization. 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 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 and general and administrative expense. 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.
Analysis of Historical Results of Operations
2022 Compared with 2021
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,
Year Ended December 31,
2022
2021
2022
2021
(in thousands)
(per ton/BOE sold)
Coal - Tons sold
35,589
32,268
N/A
N/A
Coal - Tons produced
35,477
32,207
N/A
N/A
Coal - Coal sales
$
2,102,229
$
1,386,923
$
59.07
$
42.98
Coal - Segment Adjusted EBITDA Expense (1) (2)
$
1,307,236
$
975,839
$
36.73
$
30.24
Oil & Gas Royalties - BOE sold
2,208
1,663
N/A
N/A
Oil & Gas Royalties - Royalties (3)
$
138,402
$
74,988
$
62.70
$
45.08
Coal Royalties - Tons sold
21,780
20,247
N/A
N/A
Coal Royalties - Intercompany royalties
$
60,624
$
51,402
$
2.78
$
2.54
(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.
(3) Average sales price per BOE is defined as oil & gas royalty revenues excluding lease bonus revenue divided by total BOE sold.
Coal sales . 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 price variance of $572.6 million due to higher average coal sales prices and a volume variance
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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 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 $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 $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 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 $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.
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Segment Information . 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:
Year Ended December 31,
2022
2021
Increase (Decrease)
(in thousands)
Segment Adjusted EBITDA
Illinois Basin Coal Operations
$
420,684
$
265,292
$
155,392
58.6
%
Appalachia Coal Operations
426,402
172,601
253,801
147.0
%
Oil & Gas Royalties
131,168
68,774
62,394
90.7
%
Coal Royalties
38,809
33,202
5,607
16.9
%
Other, Corporate and Elimination (1)
3,495
9,383
(5,888)
(62.8)
%
Total Segment Adjusted EBITDA (2)
$
1,020,558
$
549,252
$
471,306
85.8
%
Coal - Tons sold
Illinois Basin Coal Operations
24,110
22,264
1,846
8.3
%
Appalachia Coal Operations
11,479
10,004
1,475
14.7
%
Total tons sold
35,589
32,268
3,321
10.3
%
Coal sales
Illinois Basin Coal Operations
$
1,219,943
$
873,930
$
346,013
39.6
%
Appalachia Coal Operations
882,286
512,993
369,293
72.0
%
Total coal sales
$
2,102,229
$
1,386,923
$
715,306
51.6
%
Other revenues
Illinois Basin Coal Operations
$
6,822
$
4,666
$
2,156
46.2
%
Appalachia Coal Operations
1,481
3,940
(2,459)
(62.4)
%
Oil & Gas Royalties
3,039
2,197
842
38.3
%
Coal Royalties
56
69
(13)
(18.8)
%
Other, Corporate and Elimination
40,622
27,586
13,036
47.3
%
Total other revenues
$
52,020
$
38,458
$
13,562
35.3
%
Segment Adjusted EBITDA Expense
Illinois Basin Coal Operations
$
806,080
$
613,303
$
192,777
31.4
%
Appalachia Coal Operations
464,029
344,332
119,697
34.8
%
Oil & Gas Royalties
13,950
9,943
4,007
40.3
%
Coal Royalties
21,871
18,269
3,602
19.7
%
Other, Corporate and Elimination (1)
(23,497)
(33,198)
9,701
29.2
%
Total Segment Adjusted EBITDA Expense (2)
$
1,282,433
$
952,649
$
329,784
34.6
%
Oil & Gas Royalties
Volume - BOE (3)
2,208
1,663
545
32.8
%
Oil & gas royalties
$
138,402
$
74,988
$
63,414
84.6
%
Coal Royalties
Volume - Tons sold (4)
$
21,780
20,247
$
1,533
7.6
%
Intercompany coal royalties
60,624
$
51,402
9,222
17.9
%
(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.
(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.'"
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(3) BOE for natural gas is calculated on a 6:1 basis (6,000 cubic feet of natural gas to one barrel).
(4) 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 to $420.7 million in 2022 from $265.3 million in 2021. 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 $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 $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 $5.6 million was a result of increased royalty tons sold and higher average royalty rates per ton.
2021 Compared with 2020
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
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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 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,
2022
2021
(in thousands)
Net income
$
579,148
$
178,755
Noncontrolling interest
(1,958)
(598)
Net income attributable to ARLP
$
577,190
$
178,157
General and administrative
80,334
70,160
Depreciation, depletion and amortization
273,759
261,377
Interest expense, net
35,297
39,141
Income tax expense
53,978
417
Consolidated Segment Adjusted EBITDA
$
1,020,558
$
549,252
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. Segment Adjusted EBITDA Expense is used as a supplemental financial measure by our management to assess the operating performance of our segments. Segment Adjusted EBITDA Expense is a key component of Segment Adjusted EBITDA in addition to coal sales, royalty revenues and other revenues. 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 operating expenses, the most comparable GAAP financial measure, to consolidated Segment Adjusted EBITDA Expense:
Year Ended December 31,
2022
2021
(in thousands)
Operating expenses (excluding depreciation, depletion and amortization)
$
1,286,635
$
943,257
Outside coal purchases
151
6,372
Other expense (income)
(4,353)
3,020
Segment Adjusted EBITDA Expense
$
1,282,433
$
952,649
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Ongoing Acquisition Activities
Consistent with our business strategy, from time to time we engage in discussions with potential sellers regarding our possible acquisitions of certain assets and/or companies of the sellers. For more information on acquisitions, please read "Item 8. 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.
Liquidity and Capital Resources
Liquidity
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. 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 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. Please see "Item 1A. Risk Factors."
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.
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. 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, 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. Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities" for more information on the unit repurchase program.
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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 Flows
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, 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 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 net borrowings and payments on equipment financings, and on the revolving credit and securitization facilities, mostly offset by increased distributions to partners.
Cash Requirements
We currently estimate our 2023 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 $757.0 million to $807.0 million. Management anticipates having sufficient cash flow to meet 2023 cash requirements with our December 31, 2022 cash and cash equivalents of $296.0 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 $7.05 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 10 – Leases," "—Note 17 – Employee Benefit Plans," "—Note 20 – Asset Retirement Obligations," "—Note 21 – Accrued Workers' Compensation and Pneumoconiosis Benefits" and "—Note 23 – 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.
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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, 2022:
Workers'
Reclamation
Compensation
Obligation
Obligation
Other
Total
(in millions)
Surety bonds
$
174.3
$
58.8
$
11.3
$
244.4
Letters of credit
—
41.0
16.8
57.8
Insurance
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. Wildcat Insurance charged certain of our subsidiaries for the premiums on this program and in return purchased reinsurance for the program in the standard market. 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 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. Also, exposures exist for which no insurance may be available and for which we have not reserved. In addition, the insurance industry has been subject to efforts by environmental activists to restrict coverages available for fossil-fuel companies.
Debt Obligations
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
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. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances. We discuss these estimates and judgments with the audit committee of the Board of Directors ("Audit Committee") periodically. 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. The following critical accounting policies are materially impacted by judgments, assumptions and estimates used in the preparation of our consolidated financial statements:
Business Combinations and Goodwill
We account for business acquisitions using the purchase method of accounting. See "Item 8. Financial Statements and Supplementary Data—Note 3 – 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, 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. Accordingly, it is not uncommon for the initial estimates to be subsequently revised. The results of operations of acquired businesses are included in the consolidated financial statements from the acquisition date.
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.
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The only indefinite-lived intangible that the Partnership currently has is goodwill. 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. The reporting unit or units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed or operated. A reporting unit is an operating segment or a component that is one level below an operating segment.
The Partnership computes the fair value of its reporting units primarily using the income approach (discounted cash flow analysis). The computations require management to make significant estimates. Critical estimates are used as part of these evaluations include, among other things, the discount rate applied to future earnings reflecting a weighted average cost of capital rate, and projected coal price assumptions. 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 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. The forecast assumptions used in our assessments make certain assumptions about future pricing, volumes and expected maintenance capital expenditures. Assumptions are also made for a "normalized" perpetual growth rate for periods beyond the long range financial forecast period.
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 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, 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 2022 or 2021.
Our estimates of fair value are sensitive to changes in variables, certain of which relate to broader macroeconomic conditions outside our control. 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 or elevated energy prices due to geopolitical impacts such as Russia's invasion of Ukraine. 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. While we believe we have made reasonable estimates and assumptions to calculate the fair value of the reporting units and other intangible assets, it is possible a material change could occur. See "Item 8. Financial Statements and Supplementary Data—Note 5 – Goodwill Impairment."
Oil & Gas Reserve Values
Estimated oil & gas reserves and estimated market prices for oil & gas are a significant part of our depletion calculations, impairment analyses, and other estimates. Following are examples of how these estimates affect financial results:
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● an increase (decrease) in estimated proved oil & gas reserves can reduce (increase) our units of production depreciation, depletion and amortization rates; and
● changes in oil & gas reserves and estimated market prices both impact projected future cash flows from our mineral interests. This in turn can impact our periodic impairment analysis.
The process of estimating oil & gas reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. After being estimated internally, our proved reserves estimates are compared to proved reserves that are audited by independent experts in connection with our required year-end reporting. The data may change substantially over time as a result of numerous factors, including the historical 12 month average price, additional development cost and activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates could occur from time to time. Such changes could trigger an impairment of our oil & gas mineral interests and have an impact on our depreciation, depletion and amortization expense prospectively.
Estimates of future commodity prices utilized in our impairment analyses consider market information including published forward oil & gas prices. The forecasted price information used in our impairment analyses is consistent with that generally used in evaluating third party operator drilling decisions and our expected acquisition plans, if any. Prices for future periods will impact the production economics underlying oil & gas reserve estimates. In addition, changes in the price of oil & gas also impact certain costs associated with our expected underlying production and future capital costs. The prices of oil & gas are volatile and change from period to period, thus are expected to impact our estimates. Significant unfavorable changes in the estimated future commodity prices could result in an impairment of our oil & gas mineral interests.
Workers ' Compensation and Pneumoconiosis (Black Lung) Benefits
We provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. We generally provide for these claims through self-insurance programs. Workers' compensation laws also compensate survivors of workers who suffer employment related deaths. Our liability for traumatic injury claims is the estimated present value of current workers' compensation benefits, based on our actuary estimates. Our actuarial calculations are based on a blend of actuarial projection methods and numerous assumptions including claim development patterns, mortality, medical costs and interest rates. See "Item 8. Financial Statements and Supplementary Data—Note 21 – Accrued Workers' Compensation and Pneumoconiosis Benefits" for additional discussion. 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. We limit our exposure to traumatic injury claims by purchasing a high deductible insurance policy that starts paying benefits after deductibles for a particular claim year have been met. Our receivables for traumatic injury claims under this policy as of December 31, 2022 and 2021 are $4.1 million and $5.7 million, respectively.
Coal mining companies are subject to Federal Coal Mine Health and Safety Act of 1969, as amended, and various state statutes for the payment of medical and disability benefits to eligible recipients related to coal worker's pneumoconiosis, or black lung. We provide for these claims through self-insurance programs. Our pneumoconiosis benefits liability is calculated using the service cost method based on the actuarial present value of the estimated pneumoconiosis benefits obligation. Our actuarial calculations are based on numerous assumptions including disability incidence, medical costs, mortality, death benefits, dependents and discount rates. We had accrued liabilities of $104.3 million and $111.3 million for the pneumoconiosis benefits at December 31, 2022 and 2021, respectively. A one-percentage-point reduction in the discount rate would have increased the expense recognized for the year ended December 31, 2022 by approximately $3.0 million. Under the service cost method used to estimate our pneumoconiosis benefits liability, actuarial gains or losses attributable to changes in actuarial assumptions, such as the discount rate, are amortized over the remaining service period of active miners.
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 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.
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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 on estimated undiscounted future cash flows. Long-lived assets and certain intangibles are not reviewed for impairment unless an impairment indicator is noted. Several examples of impairment indicators include:
● A significant decrease in the market price of a long-lived asset;
● A significant adverse change in the extent or manner in which a long-lived asset is being used or in its physical condition;
● A significant adverse change in legal factors or in the business climate that could affect the value of a long-lived asset, including an adverse action of assessment by a regulator;
● An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
● A current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset; or
● A current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. The term more likely that not refers to a level of likelihood that is more than 50 percent.
The above factors are not all inclusive, and management must continually evaluate whether other factors are present that would indicate a long-lived asset may be impaired. If there is an indication that the carrying amount of an asset may not be recovered, we compare our estimate of undiscounted future cash flows attributable to the asset to the carrying value of the asset. Individual assets are grouped for impairment review purposes based on the lowest level for which there is identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a by-mine basis. Assumptions about sales, operating margins, capital expenditures and sales prices are based on our budgets, business plans, economic projections, and anticipated future cash flows. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, t he amount of impairment is measured by the difference between the carrying value and the fair value of the asset. 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 an asset impairment of $25.0 million in 2020. See "Item 8. Financial Statements and Supplementary Data—Note 4 – Long-Lived Asset Impairments".
Asset Retirement Obligations
SMCRA and similar state statutes require that mined property be restored in accordance with specified standards and an approved reclamation plan. A liability is recorded for the estimated cost of future mine asset retirement and closing procedures on a present value basis when incurred or acquired and a corresponding amount is capitalized by increasing the carrying amount of the related long-lived asset. Those costs relate to permanently sealing portals at underground mines and to reclaiming the final pits and support surface acreage for both our underground mines and past surface mines. Examples of these types of costs, common to both types of mining, include, but are not limited to, removing or covering refuse piles and settling ponds, water treatment obligations, and dismantling preparation plants, other facilities and roadway infrastructure. Accrued liabilities of $149.8 million and $131.1 million for these costs are recorded at December 31, 2022 and 2021, respectively. See "Item 8. Financial Statements and Supplementary Data—Note 20 – Asset Retirement Obligations" for additional information. The liability for asset retirement and closing procedures is sensitive to changes in cost estimates, estimated mine lives and timing of post-mine reclamation activities. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free interest rate.
Accounting for asset retirement obligations also requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. 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
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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.
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. Discounting resulted in reducing the accrual for asset retirement obligations by $110.4 million and $98.3 million at December 31, 2022 and 2021. We estimate that the aggregate undiscounted cost of final mine closure is approximately $260.2 million and $229.4 million at December 31, 2022 and 2021, respectively. If our assumptions differ from actual experiences, or if changes in the regulatory environment occur, our actual cash expenditures and costs that we incur could be materially different than currently estimated.
Shelf Registration Statement
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"). As of February 24, 2023, we had not utilized any amounts available under the 2022 Registration Statement.
Related – Party Transactions
See "Item 8. Financial Statements and Supplementary Data—Note 22 – Related-Party Transactions" for a discussion of our related-party transactions.
Accruals of Other Liabilities
We had accruals for other liabilities, including current obligations, totaling $395.3 million and $318.9 million at December 31, 2022 and 2021, respectively. These accruals were chiefly comprised of workers' compensation benefits, pneumoconiosis benefits, and costs associated with asset retirement obligations. These obligations are self-insured except for certain excess insurance coverage for workers' compensation. The accruals of these items were based on estimates of future expenditures based on current legislation, related regulations and other developments. Thus, from time to time, our results of operations may be significantly affected by changes to these liabilities. Please see "Item 8. Financial Statements and Supplementary Data—Note 20 – Asset Retirement Obligations" and "—Note 21 – Accrued Workers' Compensation and Pneumoconiosis Benefits."
Inflation
Any future inflationary or deflationary pressures could adversely affect the results of our operations. 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."
New Accounting Standards
See "Item 8. Financial Statements and Supplementary Data—Note 2 – Summary of Significant Accounting Policies" for a discussion of new accounting standards.