Item 2. Management’s Discussion and Analysis
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Significant relationships referenced in this management's discussion and analysis of financial condition and results of operations include the following:
● References to "we," "us," "our" or "ARLP Partnership" mean the business and operations of Alliance Resource Partners, L.P., the parent company, as well as its consolidated subsidiaries.
● References to "ARLP" mean Alliance Resource Partners, L.P., individually as the parent company, and not on a consolidated basis.
● References to "MGP" mean Alliance Resource Management GP, LLC, ARLP's general partner.
● References to "Mr. Craft" mean Joseph W. Craft III, the Chairman, President and Chief Executive Officer of MGP.
● References to "Intermediate Partnership" mean Alliance Resource Operating Partners, L.P., the intermediate partnership of Alliance Resource Partners, L.P.
● References to "Alliance Coal" mean Alliance Coal, LLC, the holding company for our coal mining operations.
● References to "Alliance Minerals" mean Alliance Minerals, LLC, the holding company for our oil and gas minerals interests.
● References to "Alliance Resource Properties" mean Alliance Resource Properties, LLC, the land holding company for certain of our coal mineral interests, including the subsidiaries of Alliance Resource Properties, LLC.
Summary
We are a diversified natural resource company operating in the United States 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. We began coal mining operations in 1971 and, since then, have grown through acquisitions and internal development in strategic producing regions to become the second largest coal producer in the eastern United States. 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. Two of our mines are located on the banks of the Ohio River. As is customary in the coal industry, we have entered into long-term coal supply agreements with many of our customers. In addition to our mining operations, in 2007, Alliance Resource Properties began acquiring control of coal mineral interests and leasing the coal reserves to our mining operations. In 2014, we began acquiring oil & gas mineral interests in premier oil & gas producing regions across the United States.
We have 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 and transportation methods and regulatory issues. The two coal operations reportable segments include seven mining complexes operating in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia and a coal loading terminal in Indiana on the Ohio River. Our 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 55,500 net royalty acres which provides us with diversified exposure to industry leading operators consistent with our general business strategy to grow our oil & gas mineral interest business. We market our oil & gas mineral interests for lease to operators in those regions and generate royalty income from the leasing and development of those mineral interests. Our Coal Royalties reportable segment includes coal reserves controlled by Alliance Resource Properties, which are either (a) leased to certain of our coal mining entities or (b) unleased but near our coal mining operations.
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 have similar management attributes. As a result, we restructured our reportable segments to better reflect this strategic view in how we manage our business and allocate resources. Prior periods 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
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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, LLC ("Gibson") mining complex, which includes the Gibson South mine, (b) the Warrior Coal, LLC ("Warrior") mining complex, (c) the River View Coal, LLC ("River View") mining complex and (d) the Hamilton County Coal, LLC ("Hamilton") mining complex. The Illinois Basin Coal Operations reportable segment also includes our operating Mt. Vernon Transfer Terminal, LLC ("Mt. Vernon") coal loading terminal in Indiana on the Ohio River. Our Coal Royalties reportable segment controls other coal reserves near our Illinois Basin operations, which have not yet been leased to our Illinois Basin mining entities.
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) the Gibson North mine, which ceased production in fourth quarter of 2019, (b) Webster County Coal, LLC's Dotiki mining complex, (c) White County Coal, LLC's Pattiki mining complex, (d) Hopkins County Coal, LLC's mining complex, and (e) Sebree Mining, LLC's mining complex.
● Appalachia Coal Operations reportable segment includes currently operating mining complexes (a) the Mettiki mining complex, (b) the Tunnel Ridge, LLC mining complex ("Tunnel Ridge"), and (c) the MC Mining, LLC mining complex ("MC Mining"). The Mettiki mining complex includes Mettiki Coal (WV), LLC's Mountain View mine and Mettiki Coal, LLC's preparation plant. Our Coal Royalties reportable segment discussed below, controls the Penn Ridge coal reserves near our Tunnel Ridge operations which have not yet been leased to Tunnel Ridge.
● Oil & Gas Royalties reportable segment includes oil & gas mineral interests held by AR Midland, LP ("AR Midland") and AllDale I & II and includes Alliance Minerals' equity interests in both AllDale Minerals III, LP ("AllDale III") (Note 9 – Investment) and Cavalier Minerals. Please read "Item 1. Financial Statements (Unaudited) — Note 9 – Investment" of this Quarterly Report on Form 10-Q for more information on AllDale III.
● Coal Royalties reportable segment includes coal reserves held or controlled by Alliance Resource Properties, consisting of (a) reserves leased to certain of our mining complexes in both the Illinois Basin Coal Operations and Appalachia Coal Operations reportable segments and (b) reserves near our coal mining operations but not yet leased to our coal mining entities. About 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, Matrix Design Group, LLC and its subsidiaries ("Matrix Design"), Alliance Design Group, LLC ("Alliance Design") (collectively, Matrix Design and Alliance Design referred to as the "Matrix Group"), Pontiki Coal, LLC's workers' compensation and pneumoconiosis liabilities, Wildcat Insurance, LLC ("Wildcat Insurance"), which assists the ARLP Partnership with its insurance requirements, AROP Funding and Alliance Finance (both discussed in Note 7 – 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. Please read "Item 1. Financial Statements (Unaudited) — Note 7 – Long-Term Debt" of this Quarterly Report on Form 10-Q for more information on AROP Funding.
Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020
We reported net income attributable to ARLP of $57.5 million for the three months ended September 30, 2021 ("2021 Quarter") compared to $27.2 million for the three months ended September 30, 2020 ("2020 Quarter"). The increase of $30.3 million was primarily due to higher revenues, partially offset by increased total operating expenses. Total revenues in the 2021 Quarter increased by 16.8% to $415.4 million compared to $355.7 million in the 2020 Quarter as a result of higher coal sales volumes and significantly higher oil & gas prices. In general, results from coal operations and oil & gas royalties for the 2021 Quarter were significantly improved compared to the 2020 Quarter, which was negatively impacted by the COVID-19 pandemic.
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Three Months Ended September 30,
2021
2020
2021
2020
(in thousands)
(per ton / per BOE sold)
Coal - Tons sold
8,494
7,702
N/A
N/A
Coal - Tons produced
7,986
7,202
N/A
N/A
Coal - Coal sales
$
362,264
$
335,767
$
42.65
$
43.59
Coal - Segment Adjusted EBITDA Expense (1) (2)
$
245,909
$
222,146
$
28.95
$
28.84
Oil & Gas Royalties - BOE sold
414
468
N/A
N/A
Oil & Gas Royalties - Royalties (3)
$
20,109
$
9,693
$
48.64
$
20.71
Coal Royalties - Tons sold
5,344
5,098
N/A
N/A
Coal Royalties - Intercompany royalties
$
13,456
$
11,406
$
2.52
$
2.24
(1) For a definition of Segment Adjusted EBITDA Expense and related reconciliation to comparable generally accepted accounting principles ("GAAP") financial measures, please see below under "—Reconciliation of non-GAAP "Segment Adjusted EBITDA Expense" to GAAP "Operating Expenses."
(2) Coal - Segment Adjusted EBITDA Expense is defined as consolidated Segment Adjusted EBITDA Expense excluding expenses of our Oil & Gas Royalties segment and is adjusted for intercompany transactions with our Coal Royalties segment.
(3) Average sales price per BOE is defined as oil & gas royalty revenues excluding lease bonus revenue divided by total BOE sold.
Coal sales . Coal sales increased $26.5 million or 7.9% to $362.3 million for the 2021 Quarter from $335.8 million for the 2020 Quarter. The increase was attributable to a volume variance of $34.5 million resulting from increased tons sold, partially offset by a price variance of $8.0 million due to lower average coal sales prices. Improved coal demand primarily in the export markets during the 2021 Quarter drove coal sales volumes higher by 10.3% to 8.5 million tons sold compared to 7.7 million tons sold in the 2020 Quarter, which was adversely impacted by the pandemic. Coal sales price realizations decreased by 2.2% in the 2021 Quarter to $42.65 per ton sold, compared to $43.59 per ton sold during the 2020 Quarter, due to the expiration of higher priced contract shipments.
Coal - Segment Adjusted EBITDA Expense . Segment Adjusted EBITDA Expense for our coal operations increased 10.7% to $245.9 million, as a result of higher coal sales volumes. On a per ton basis, Segment Adjusted EBITDA Expense for our coal operations increased slightly in the 2021 Quarter to $28.95 per ton sold, compared to $28.84 per ton in the 2020 Quarter, primarily due to certain cost increases, which are discussed below by category:
● Material and supplies expenses per ton produced increased 8.4% to $10.38 per ton in the 2021 Quarter from $9.58 per ton in the 2020 Quarter. The increase of $0.80 per ton produced primarily reflects increases of $0.78 per ton for roof support, $0.33 per ton for contract labor used in the mining process and $0.24 per ton for power and fuel used in the mining process, partially offset by a decrease of $0.43 per ton in longwall subsidence expense.
● Outside coal purchases increased $6.1 million in the 2021 Quarter as a result of sales from purchased coal, which generally costs higher on a per ton basis than our produced coal.
Segment Adjusted EBITDA Expense increases per ton were partially offset by the following decreases:
● Labor and benefit expenses per ton produced, excluding workers' compensation, decreased 11.5% to $9.19 per ton in the 2021 Quarter from $10.39 per ton in the 2020 Quarter. The decrease of $1.20 per ton was primarily due to a) increased volumes which in turn lowered certain fixed costs per ton, b) reduced benefit accruals and c) favorable medical adjustments.
● Workers' compensation expenses per ton produced decreased to $(0.07) per ton in the 2021 Quarter from $0.45 per ton in the 2020 Quarter. The decrease of $0.52 per ton produced resulted primarily from refunds received in the 2021 Quarter on assessments paid to the state of Kentucky in prior years.
Oil & gas royalties. Oil & gas royalty revenues increased to $20.1 million in the 2021 Quarter compared to $9.7 million for the 2020 Quarter. The increase of $10.4 million was primarily due to significantly higher sales price realizations per BOE discussed above.
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Other revenues . Other revenues were principally comprised of Matrix Design sales and other miscellaneous sales and revenue activities. Other revenues increased to $11.0 million in the 2021 Quarter from $4.0 million in the 2020 Quarter. The increase of $7.0 million was primarily due to increased sales of mining technology products by our Matrix Design subsidiary and other smaller variances in the 2021 Quarter.
Depreciation, depletion and amortization. Depreciation, depletion and amortization expense decreased to $68.8 million for the 2021 Quarter compared to $80.2 million for the 2020 Quarter primarily as a result of increased mine life estimates for certain mines and reduced depreciation associated with coal inventory changes.
Transportation revenues and expenses . Transportation revenues and expenses were $22.0 million and $6.2 million for the 2021 and 2020 Quarters, respectively. The increase of $15.8 million was primarily attributable to increased average third-party transportation rates in the 2021 Quarter and increased coal shipments to international markets for which we arrange third-party transportation. Transportation revenues are recognized when title to the coal passes to the customer and recognized in an amount equal to the corresponding transportation expenses.
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Segment Adjusted EBITDA. Our 2021 Quarter Segment Adjusted EBITDA increased $21.9 million to $154.6 million from the 2020 Quarter Segment Adjusted EBITDA of $132.7 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:
Three Months Ended
September 30,
2021
2020
Increase (Decrease)
(in thousands)
Segment Adjusted EBITDA
Illinois Basin Coal Operations
$
69,305
$
75,583
$
(6,278)
(8.3)
%
Appalachia Coal Operations
52,726
43,105
9,621
22.3
%
Oil & Gas Royalties
19,080
8,898
10,182
114.4
%
Coal Royalties
9,198
6,287
2,911
46.3
%
Other, Corporate and Elimination (2)
4,280
(1,172)
5,452
(1)
Total Segment Adjusted EBITDA (3)
$
154,589
$
132,701
$
21,888
16.5
%
Coal - Tons sold
Illinois Basin Coal Operations
5,750
5,219
531
10.2
%
Appalachia Coal Operations
2,744
2,483
261
10.5
%
Total tons sold
8,494
7,702
792
10.3
%
Coal sales
Illinois Basin Coal Operations
$
217,637
$
206,356
$
11,281
5.5
%
Appalachia Coal Operations
144,627
129,411
15,216
11.8
%
Total coal sales
$
362,264
$
335,767
$
26,497
7.9
%
Other revenues
Illinois Basin Coal Operations
$
1,335
$
241
$
1,094
(1)
Appalachia Coal Operations
411
395
16
4.1
%
Oil & Gas Royalties
1,082
28
1,054
(1)
Coal Royalties
—
42
(42)
(100.0)
%
Other, Corporate and Elimination
8,211
3,259
4,952
151.9
%
Total other revenues
$
11,039
$
3,965
$
7,074
178.4
%
Segment Adjusted EBITDA Expense
Illinois Basin Coal Operations
$
149,666
$
131,014
$
18,652
14.2
%
Appalachia Coal Operations
92,312
86,701
5,611
6.5
%
Oil & Gas Royalties
2,639
849
1,790
210.8
%
Coal Royalties
4,258
5,161
(903)
(17.5)
%
Other, Corporate and Elimination (2)
(9,525)
(6,975)
(2,550)
(36.6)
%
Total Segment Adjusted EBITDA Expense
$
239,350
$
216,750
$
22,600
10.4
%
Oil & Gas Royalties
Volume - BOE (4)
414
468
(54)
(11.5)
%
Oil & gas royalties
$
20,109
$
9,693
$
10,416
107.5
%
Coal Royalties
Volume - Tons sold (5)
5,344
5,098
246
4.8
%
Intercompany coal royalties
$
13,456
$
11,406
$
2,050
18.0
%
(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.
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(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) Barrels of oil equivalent ("BOE") 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 reserves leased from our Coal Royalties Segment.
Illinois Basin Coal Operations – Segment Adjusted EBITDA decreased to $69.3 million in the 2021 Quarter from $75.6 million in the 2020 Quarter. The decrease of $6.3 million was primarily attributable to lower coal sales price realizations and higher expenses per ton, partially offset by increased coal sales volumes. Coal sales increased 5.5% to $217.6 million in the 2021 Quarter from $206.4 million in the 2020 Quarter resulting from higher sales volumes, which increased 10.2% due to improved coal demand primarily in the export markets. Coal sales price per ton sold in the 2021 Quarter decreased by 4.3% compared to the 2020 Quarter reflecting the expiration of higher-priced sales contracts and a greater mix of lower-priced export sales volumes. Segment Adjusted EBITDA Expense increased 14.2% to $149.7 million in the 2021 Quarter from $131.0 million in the 2020 Quarter primarily as a result of increased sales volumes and higher expenses per ton. Segment Adjusted EBITDA Expense per ton increased $0.93 per ton sold to $26.03 from $25.10 per ton sold in the 2020 Quarter primarily as a result of increased roof support and maintenance expenses as well as higher labor costs per ton across the region. These increases were partially offset by reduced benefit accruals and workers compensation refunds received in the 2021 Quarter.
Appalachia Coal Operations – Segment Adjusted EBITDA increased 22.3% to $52.7 million for the 2021 Quarter from $43.1 million in the 2020 Quarter. The increase of $9.6 million was primarily attributable to higher coal sales, which increased 11.8% to $144.6 million in the 2021 Quarter from $129.4 million in the 2020 Quarter. The increase in coal sales reflects higher tons sold, which rose 10.5% in the 2021 Quarter compared to the 2020 Quarter due to increased sales volumes at our Tunnel Ridge and MC Mining operations resulting from improved market conditions. Segment Adjusted EBITDA Expense increased 6.5% to $92.3 million in the 2021 Quarter from $86.7 million in the 2020 Quarter due to increased sales volumes, partially offset by lower expenses per ton. Segment Adjusted EBITDA Expense per ton decreased $1.28 per ton sold to $33.64 compared to $34.92 per ton sold in the 2020 Quarter, as a result of increased volumes and reduced longwall subsidence expense in the 2021 Quarter and a longwall move in the 2020 Quarter at our Tunnel Ridge mine, the production benefits from MC Mining’s transition of mining operations to a new reserve area in the second half of 2020 and the benefits of ongoing expense control and efficiency initiatives. In addition, see certain cost variances described above under "–Coal - Segment Adjusted EBITDA Expense."
Oil & Gas Royalties – Segment Adjusted EBITDA increased to $19.1 million for the 2021 Quarter from $8.9 million in the 2020 Quarter. The increase of $10.2 million was primarily due to significantly higher sales price realizations per BOE in the 2021 Quarter compared to the 2020 Quarter, which more than offset lower volumes and higher Segment Adjusted EBITDA Expense.
Coal Royalties – Segment Adjusted EBITDA increased 46.3% to $9.2 million for the 2021 Quarter from $6.3 million in the 2020 Quarter. The increase of $2.9 million was a result of increased royalty tons sold and higher average royalty rates per ton.
Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020
We reported net income attributable to ARLP of $126.3 million for the nine months ended September 30, 2021 ("2021 Period") compared to a net loss attributable to ARLP of $164.2 million for the nine months ended September 30, 2020 ("2020 Period"). The increase of $290.5 million resulted from higher revenues and lower depreciation in the 2021 Period and $157.0 million of non-cash impairment charges in the 2020 Period. Increased coal sales volumes and oil & gas prices in the 2021 Period drove total revenues higher by 14.0% to $1.10 billion, compared to $961.6 million for the 2020 Period. In general, results from coal operations and oil & gas royalties for the 2021 Period were significantly improved compared to the 2020 Period, 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.
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Nine Months Ended September 30,
2021
2020
2021
2020
(in thousands)
(per ton / per BOE sold)
Coal - Tons sold
23,168
20,139
N/A
N/A
Coal - Tons produced
23,468
19,546
N/A
N/A
Coal - Coal sales
$
975,725
$
886,690
$
42.12
$
44.03
Coal - Segment Adjusted EBITDA Expense (1) (2)
$
667,708
$
653,044
$
28.82
$
32.43
Oil & Gas Royalties - BOE sold
1,205
1,374
N/A
N/A
Oil & Gas Royalties - Royalties (3)
$
51,222
$
31,718
$
42.52
$
23.08
Coal Royalties - Tons sold
14,572
13,537
N/A
N/A
Coal Royalties - Intercompany royalties
$
36,410
$
29,555
$
2.50
$
2.18
(1) For a definition of Segment Adjusted EBITDA Expense and related reconciliation to comparable generally accepted accounting principles ("GAAP") financial measures, please see below under "—Reconciliation of non-GAAP "Segment Adjusted EBITDA Expense" to GAAP "Operating Expenses."
(2) Coal - Segment Adjusted EBITDA Expense is defined as consolidated Segment Adjusted EBITDA Expense excluding expenses of our Oil & Gas Royalties segment and is adjusted for intercompany transactions with our Coal Royalties segment.
(3) Average sales price per BOE is defined as oil & gas royalty revenues excluding lease bonus revenue divided by total BOE sold.
Coal sales . Coal sales increased $89.0 million or 10.0% to $975.7 million for the 2021 Period from $886.7 million for the 2020 Period. The increase was attributable to a volume variance of $133.4 million resulting from increased tons sold partially offset by a negative price variance of $44.4 million due to lower average coal sales prices. Tons sold increased 15.0% to 23.2 million tons in the 2021 Period due to improved coal demand and increased export shipments. Primarily due to the expiration of higher priced contract shipments, coal sales price realizations declined 4.3% in the 2021 Period to $42.12 per ton sold, compared to $44.03 per ton sold during the 2020 Period. Production volumes increased by 20.1% in the 2021 Period, reflecting the temporary idling and scaling back of production at certain mines during the 2020 Period in response to weak market conditions resulting from the pandemic.
Coal - Segment Adjusted EBITDA Expense . Segment Adjusted EBITDA Expense for our coal operations was comparable to the 2020 Period as increased expenses resulting from higher sales volumes in the 2021 Period were primarily offset by reduced per ton costs in the 2021 Period. Segment Adjusted EBITDA Expense per ton decreased 11.1% in the 2021 Period to $28.82 per ton, compared to $32.43 per ton in the 2020 Period. The decrease was attributed primarily to increased volumes lowering fixed costs per ton, lower inventory charges, improved recoveries at several 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 15.4% to $9.32 per ton in the 2021 Period from $11.02 per ton in the 2020 Period. The decrease of $1.70 per ton was primarily due to increased volumes at our Illinois Basin mines where production was temporarily idled in the 2020 Period in response to weak market conditions resulting from the pandemic.
● Workers' compensation expenses per ton produced decreased to $0.18 per ton in the 2021 Period from $0.63 per ton in the 2020 Period. The decrease of $0.45 per ton produced resulted from refunds received in the 2021 Period on assessments paid to the state of Kentucky in prior years and favorable mid-year workers' compensation accrual adjustments in the 2021 Period, primarily due to an increase in the discount rate, compared to the 2020 Period, which had a valuation loss due to unfavorable changes in claims development and a decrease in the discount rate.
● Material and supplies expenses per ton produced decreased 6.5% to $9.85 per ton in the 2021 Period from $10.53 per ton in the 2020 Period. The decrease of $0.68 per ton produced primarily reflects decreases of $0.47 per ton for outside expenses used in the mining processes, $0.25 per ton for environmental and reclamation expenses other than longwall subsidence and $0.19 per ton for power and fuel used in the mining process, partially offset by an increase of $0.51 per ton for roof support.
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● Maintenance expenses per ton produced decreased 17.0% to $2.68 per ton in the 2021 Period from $3.23 per ton in the 2020 Period. The decrease of $0.55 per ton produced was primarily due to increased production and improved recoveries previously mentioned.
Oil & gas royalties. Oil & gas royalty revenues increased to $51.2 million in the 2021 Period compared to $31.7 million for the 2020 Period. The increase of $19.5 million was primarily due to significantly higher sales price realizations per BOE.
Other revenues . Other revenues were principally comprised of Matrix Design sales and other miscellaneous sales and revenue activities. Other revenues decreased to $24.4 million in the 2021 Period from $26.5 million in the 2020 Period. The decrease of $2.1 million was primarily due to a customer buy-out of certain coal contracts at our Tunnel Ridge mine during the 2020 Period, partially offset by increased sales of mining technology products by our Matrix Design subsidiary in the 2021 Period.
Depreciation, depletion and amortization. Depreciation, depletion and amortization expense decreased to $192.7 million for the 2021 Period compared to $237.7 million for the 2020 Period 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 impairment. During the 2020 Period, we recorded $25.0 million of non-cash asset impairment charges due to sealing our idled Gibson North mine, resulting in its permanent closure, and a decrease in the fair value of certain mining equipment and greenfield coal reserves as a result of weakened coal market conditions. Please read "Item 1. Financial Statements (Unaudited)—Note 2 – Long-Lived Asset Impairments" of this Quarterly Report on Form 10-Q.
Goodwill impairment. During the 2020 Period, we recorded a $132.0 million non-cash goodwill impairment charge associated with our Hamilton mine, primarily as the result of reduced expected production volumes due to weakened coal market conditions and low energy demand resulting in part from the COVID-19 pandemic. Please read "Item 1. Financial Statements (Unaudited)— Note 3 – Goodwill Impairment " of this Quarterly Report on Form 10-Q.
Transportation revenues and expenses . Transportation revenues and expenses were $45.2 million and $16.7 million for the 2021 and 2020 Periods, respectively. The increase of $28.5 million was primarily attributable to increased average third-party transportation rates in the 2021 Period and increased coal shipments to international markets for which we arrange third-party transportation. Transportation revenues are recognized when title to the coal passes to the customer and recognized in an amount equal to the corresponding transportation expenses.
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Segment Adjusted EBITDA. Our 2021 Period Segment Adjusted EBITDA increased $94.0 million, or 30.7%, to $400.5 million from the 2020 Period Segment Adjusted EBITDA of $306.5 million. Segment Adjusted EBITDA, tons sold, coal sales, other revenues, Segment Adjusted EBITDA Expense, oil & gas royalties, BOE volume, coal royalties and coal royalties tons sold by segment are as follows:
Nine Months Ended
September 30,
2021
2020
Increase (Decrease)
(in thousands)
Segment Adjusted EBITDA
Illinois Basin Coal Operations
$
197,601
$
141,583
$
56,018
39.6
%
Appalachia Coal Operations
125,873
120,686
5,187
4.3
%
Oil & Gas Royalties
46,405
29,534
16,871
57.1
%
Coal Royalties
23,253
16,953
6,300
37.2
%
Other, Corporate and Elimination (2)
7,370
(2,298)
9,668
(1)
Total Segment Adjusted EBITDA (3)
$
400,502
$
306,458
$
94,044
30.7
%
Coal - Tons sold
Illinois Basin Coal Operations
15,935
13,625
2,310
17.0
%
Appalachia Coal Operations
7,233
6,514
719
11.0
%
Total tons sold
23,168
20,139
3,029
15.0
%
Coal sales
Illinois Basin Coal Operations
$
610,435
$
539,614
$
70,821
13.1
%
Appalachia Coal Operations
365,290
347,076
18,214
5.2
%
Total coal sales
$
975,725
$
886,690
$
89,035
10.0
%
Other revenues
Illinois Basin Coal Operations
$
2,590
$
1,633
$
957
58.6
%
Appalachia Coal Operations
1,078
14,456
(13,378)
(92.5)
%
Oil & Gas Royalties
1,576
113
1,463
(1)
Coal Royalties
—
47
(47)
(100.0)
%
Other, Corporate and Elimination
19,160
10,237
8,923
87.2
%
Total other revenues
$
24,404
$
26,486
$
(2,082)
(7.9)
%
Segment Adjusted EBITDA Expense
Illinois Basin Coal Operations
$
415,423
$
399,664
$
15,759
3.9
%
Appalachia Coal Operations
240,494
240,846
(352)
(0.1)
%
Oil & Gas Royalties
7,116
2,851
4,265
149.6
%
Coal Royalties
13,157
12,649
508
4.0
%
Other, Corporate and Elimination (2)
(24,619)
(17,021)
(7,598)
(44.6)
%
Total Segment Adjusted EBITDA Expense
$
651,571
$
638,989
$
12,582
2.0
%
Oil & Gas Royalties
Volume - BOE (4)
1,205
1,374
(169)
(12.3)
%
Oil & gas royalties
$
51,222
$
31,718
$
19,504
61.5
%
Coal Royalties
Volume - Tons sold (5)
14,572
13,537
1,035
7.6
%
Intercompany coal royalties
$
36,410
$
29,555
$
6,855
23.2
%
(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.
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(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) Barrels of oil equivalent ("BOE") 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 reserves leased from our Coal Royalties Segment.
Illinois Basin Coal Operations – Segment Adjusted EBITDA increased 39.6% to $197.6 million in the 2021 Period from $141.6 million in the 2020 Period. The increase of $56.0 million was primarily attributable to higher coal sales, which increased 13.1% to $610.4 million in the 2021 Period from $539.6 million in the 2020 Period. The increase of $70.8 million in coal sales primarily reflects increased sales volumes, which rose 17.0% compared to the 2020 Period 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 $415.4 million in the 2021 Period compared to $399.7 million in the 2020 Period. Segment Adjusted EBITDA Expense per ton decreased 11.1% to $26.07 from $29.33 per ton sold in the 2020 Period primarily as a result of increased volumes where production was temporarily idled and scaled back in the 2020 Period in response to weak market conditions resulting from the pandemic. Lower inventory charges and the impact of ongoing expense control and efficiency initiatives at all of our mining operations in the region also contributed to the decrease. In addition, also see certain cost variances described above under "–Coal - Segment Adjusted EBITDA Expense."
Appalachia Coal Operations – Segment Adjusted EBITDA increased 4.3% to $125.9 million for the 2021 Period from $120.7 million in the 2020 Period. The increase of $5.2 million was primarily attributable to higher coal sales, partially offset by a customer buy-out of certain coal contracts at our Tunnel Ridge mine during the 2020 Period. Coal sales increased 5.2% to $365.3 million in the 2021 Period compared to $347.1 million in the 2020 Period as a result of increased sales volumes, partially offset by lower price realizations. Tons sold increased 11.0% in the 2021 Period compared to the 2020 Period 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 the 2021 Period decreased 5.2% compared to the 2020 Period primarily due to the expiration of higher priced contract shipments. Segment Adjusted EBITDA Expense decreased slightly in the 2021 Period compared to the 2020 Period due to decreased per ton costs, partially offset by increased coal sales volumes. Segment Adjusted EBITDA Expense per ton decreased 10.1% to $33.25 compared to $36.97 per ton sold in the 2020 Period, as a result of increased sales volumes lowering fixed costs per ton, the full-year production benefit from MC Mining’s transition of mining operations to a new reserve area in the second half of 2020, ongoing expense control and efficiency initiatives and improved recoveries across the region. See also certain cost variances described above under "–Coal - Segment Adjusted EBITDA Expense."
Oil & Gas Royalties – Segment Adjusted EBITDA increased 57.1% to $46.4 million for the 2021 Period from $29.5 million in the 2020 Period. The increase of $16.9 million was primarily due to significantly higher sales price realizations per BOE, which more than offset lower volumes.
Coal Royalties – Segment Adjusted EBITDA increased 37.2% to $23.3 million for the 2021 Period from $17.0 million in the 2020 Period. The increase of $6.3 million was a result of increased royalty tons sold and higher average royalty rates per ton received from our mining subsidiaries.
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, general and administrative expenses and asset and goodwill impairments. 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.
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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 consolidated Segment Adjusted EBITDA to net income (loss), the most comparable GAAP financial measure:
Three Months Ended
Nine Months Ended
September 30,
September 30,
2021
2020
2021
2020
(in thousands)
Consolidated Segment Adjusted EBITDA
$
154,589
$
132,701
$
400,502
$
306,458
General and administrative
(18,655)
(13,871)
(51,651)
(41,131)
Depreciation, depletion and amortization
(68,763)
(80,182)
(192,698)
(237,662)
Asset impairments
—
—
—
(24,977)
Goodwill impairment
—
—
—
(132,026)
Interest expense, net
(9,389)
(11,156)
(29,595)
(34,799)
Income tax expense
(234)
(293)
(227)
(111)
Net income (loss) attributable to ARLP
$
57,548
$
27,199
$
126,331
$
(164,248)
Noncontrolling interest
176
36
384
97
Net income (loss)
$
57,724
$
27,235
$
126,715
$
(164,151)
Segment Adjusted EBITDA Expense (a non-GAAP financial measure) includes operating expenses, coal purchases and other expense. 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 consolidated Segment Adjusted EBITDA Expense to operating expense, the most comparable GAAP financial measure:
Three Months Ended
Nine Months Ended
September 30,
September 30,
2021
2020
2021
2020
(in thousands)
Segment Adjusted EBITDA Expense
$
239,350
$
216,750
$
651,571
$
638,989
Outside coal purchases
(6,065)
—
(6,179)
—
Other expense
(84)
(723)
(2,632)
(1,456)
Operating expenses (excluding depreciation, depletion and amortization)
$
233,201
$
216,027
$
642,760
$
637,533
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Liquidity and Capital Resources
Liquidity
We have historically satisfied our working capital requirements and funded our capital expenditures, investments and debt service obligations with cash generated from operations, cash provided by the issuance of debt or equity, borrowings under credit and securitization facilities and other financing transactions. We believe that existing cash balances, future cash flows from operations and investments, borrowings under credit facilities and cash provided from the issuance of debt or equity will be sufficient to meet our working capital requirements, capital expenditures and additional investments, debt payments, commitments and any distribution payments. Nevertheless, our ability to satisfy our working capital requirements, to fund planned capital expenditures, to service our debt obligations or to pay distributions will depend upon our future operating performance and access to and cost of financing sources, which will be affected by prevailing economic conditions generally, and in both the coal and oil & gas industries specifically, as well as other financial and business factors, some of which are beyond our control, including the COVID-19 pandemic. 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. 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 read "Item 1A. Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2020.
In May 2018, the Board 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 September 30, 2021, we have purchased units for a total of $93.5 million under the program. During the nine months ended September 30, 2021, we did not repurchase and retire any units. The timing of any future unit repurchases and the ultimate number of units to be purchased will depend on a number of factors, including business and market conditions, our future financial performance, and other capital priorities. Please read "Part II - Item 2. Unregistered Sales of Equity Securities and Use of Proceeds" of this Quarterly Report on Form 10-Q for more information on unit repurchase program.
Cash Flows
Cash provided by operating activities was $311.0 million for the 2021 Period compared to $291.8 million for the 2020 Period. The increase in cash provided by operating activities was primarily due to an increase in net income adjusted for non-cash items and a favorable working capital change related to accounts payable, partially offset by unfavorable working capital changes related to trade receivables and inventories compared to the 2020 Period.
Net cash used in investing activities was $80.4 million for the 2021 Period compared to $108.9 million for the 2020 Period. The decrease in cash used in investing activities was primarily attributable to the decrease in capital expenditures and an increase in accounts payable and certain other accruals related to mine infrastructure, equipment and mining operations at various mines during the 2021 Period.
Net cash used in financing activities was $181.5 million for the 2021 Period compared to $185.2 million for the 2020 Period. The decrease in cash used in financing activities was primarily attributable to lower cash distributions paid to unitholders, reduced borrowings and payments on the revolving credit facility, partially offset by increased payments and reduced borrowings on the securitization facility compared to the 2020 Period. A quarterly cash distribution of $0.40 per unit was paid in February 2020, after which payment of distributions to unitholders was temporarily suspended. Payment of quarterly distributions resumed in the 2021 Period with $0.20 per unit in total being paid for the first two quarters of the 2021 Period. Please read "Item 1. Financial Statements (Unaudited)—Note 10 – Partners' Capital" of this Quarterly Report on Form 10-Q regarding the subsequent quarterly distribution to be paid for the 2021 Quarter.
Capital Expenditures
Capital expenditures decreased to $88.7 million in the 2021 Period from $102.8 million in the 2020 Period. The decrease is primarily related to the transition to a new reserve area at MC Mining in the 2020 Period and continued expense
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control and efficiency initiatives across all our operations. Also see our discussion of "Cash Flows" above concerning the decrease in capital expenditures.
We currently project average estimated annual maintenance capital expenditures over the next five-year period of approximately $4.90 per ton produced. Our anticipated total capital expenditures, including maintenance capital expenditures, for 2021 are estimated in a range of $125.0 million to $130.0 million. Management anticipates funding remaining 2021 capital requirements with our cash and cash equivalents ($104.6 million as of September 30, 2021), cash flows from operations and investments, borrowings under revolving credit and securitization facilities and cash provided from the issuance of debt or equity. We will continue to have significant capital requirements over the long term, which may require us to incur debt or seek additional equity capital. 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.
Debt Obligations
Credit Facility. On March 9, 2020, our Intermediate Partnership entered into a Fifth Amended and Restated Credit Agreement (the "Credit Agreement") with various financial institutions. The Credit Agreement provides for a $459.5 million revolving credit facility, including a sublimit of $125 million for the issuance of letters of credit and a sublimit of $15.0 million for swingline borrowings (the "Revolving Credit Facility"), with a termination date of March 9, 2024.
The Credit Agreement is guaranteed by certain of our Intermediate Partnership's material direct and indirect subsidiaries (the "Restricted Subsidiaries") and is secured by substantially all the assets of the Restricted Subsidiaries. The Credit Agreement is also guaranteed by Alliance Minerals but the oil and gas minerals assets of Alliance Minerals and its direct and indirect subsidiaries (collectively with Alliance Minerals, the "Unrestricted Subsidiaries") are not collateral under the Credit Agreement. Borrowings under the Revolving Credit Facility bear interest, at our option, at either (i) the Base Rate at the greater of three benchmarks or (ii) a Eurodollar Rate, plus margins for (i) or (ii), as applicable, that fluctuate depending upon the ratio of Consolidated Debt to Consolidated Cash Flow (each as defined in the Credit Agreement). The Eurodollar Rate, with applicable margin, under the Revolving Credit Facility was 2.68% as of September 30, 2021. On September 30, 2021, we had $23.3 million of letters of credit outstanding with $436.2 million available for borrowing under the Revolving Credit Facility. We incur an annual commitment fee of 0.35% on the undrawn portion of the Revolving Credit Facility. We utilize the Revolving Credit Facility, as appropriate, for working capital requirements, capital expenditures and investments, scheduled debt payments and distribution payments.
The Credit Agreement contains various restrictions affecting the Intermediate Partnership and its Restricted Subsidiaries including, among other things, restrictions on incurrence of additional indebtedness and liens, sale of assets, investments, mergers and consolidations and transactions with affiliates, including transactions with Unrestricted Subsidiaries. In each case, these restrictions are subject to various exceptions. In addition, the payment of cash distributions is restricted if such payment would result in a fixed charge coverage ratio of less than 1.0 to 1.0 (as defined in the Credit Agreement) for the four most recently ended fiscal quarters. The Credit Agreement requires the Intermediate Partnership to maintain (a) a debt to cash flow ratio of not more than 2.5 to 1.0, (b) a cash flow to interest expense ratio of not less than 3.0 to 1.0 and (c) a first lien debt to cash flow ratio of not more than 1.5 to 1.0, in each case, during the four most recently ended fiscal quarters. The debt to cash flow ratio, cash flow to interest expense ratio and first lien debt to cash flow ratio were 0.95 to 1.0, 11.60 to 1.0 and 0.10 to 1.0, respectively, for the trailing twelve months ended September 30, 2021. We remained in compliance with the covenants of the Credit Agreement as of September 30, 2021 and anticipate remaining in compliance with the covenants.
Senior Notes. On April 24, 2017, the Intermediate Partnership and Alliance Resource Finance Corporation (as co-issuer), a wholly owned subsidiary of the Intermediate Partnership ("Alliance Finance"), issued an aggregate principal amount of $400.0 million of senior unsecured notes due 2025 ("Senior Notes") in a private placement to qualified institutional buyers. The Senior Notes have a term of eight years, maturing on May 1, 2025 (the "Term") and accrue interest at an annual rate of 7.5%. Interest is payable semi-annually in arrears on each May 1 and November 1. The indenture governing the Senior Notes contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of distributions or similar restricted payments, undertaking transactions with affiliates and limitations on asset sales. The issuers of the Senior Notes may redeem all or a part of the notes at any time at redemption prices set forth in the indenture governing the Senior Notes.
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Accounts Receivable Securitization. On December 5, 2014, certain direct and indirect wholly owned subsidiaries of our Intermediate Partnership entered into a $100.0 million accounts receivable securitization facility ("Securitization Facility"). Under the Securitization Facility, certain subsidiaries sell certain trade receivables on an ongoing basis to our Intermediate Partnership, which then sells the trade receivables to AROP Funding, LLC ("AROP Funding"), a wholly owned bankruptcy-remote special purpose subsidiary of our Intermediate Partnership, which in turn borrows on a revolving basis up to $100.0 million secured by the trade receivables. After the sale, Alliance Coal, as servicer of the assets, collects the receivables on behalf of AROP Funding. The Securitization Facility bears interest based on a Eurodollar Rate. The agreement governing the Securitization Facility contains customary terms and conditions, including limitations with regards to certain customer credit ratings. In January 2021, we extended the term of the Securitization Facility to January 2022 and reduced the borrowing availability under the facility to $60.0 million. The Securitization Facility was previously scheduled to mature in January 2021. On September 30, 2021, we had no outstanding balance under the Securitization Facility.
May 2019 Equipment Financing . On May 17, 2019, the Intermediate Partnership entered into an equipment financing arrangement accounted for as debt, wherein the Intermediate Partnership received $10.0 million in exchange for conveying its interest in certain equipment owned indirectly by the Intermediate Partnership and entering into a master lease agreement for that equipment (the "May 2019 Equipment Financing"). The May 2019 Equipment Financing contains customary terms and events of default and provides for thirty-six monthly payments with an implicit interest rate of 6.25%, maturing on May 1, 2022. Upon maturity, the equipment will revert to the Intermediate Partnership.
November 2019 Equipment Financing. On November 6, 2019, the Intermediate Partnership entered into an equipment financing arrangement accounted for as debt, wherein the Intermediate Partnership received $53.1 million in exchange for conveying its interest in certain equipment owned indirectly by the Intermediate Partnership and entering into a master lease agreement for that equipment (the "November 2019 Equipment Financing"). The November 2019 Equipment Financing contains customary terms and events of default and an implicit interest rate of 4.75%, providing for a four-year term with forty-seven monthly payments of $1.0 million and a balloon payment of $11.6 million upon maturity on November 6, 2023. Upon maturity, the equipment will revert to the Intermediate Partnership.
June 2020 Equipment Financing. On June 5, 2020, the Intermediate Partnership entered into an equipment financing arrangement accounted for as debt, wherein the Intermediate Partnership received $14.7 million in exchange for conveying its interest in certain equipment owned indirectly by the Intermediate Partnership and entering into a master lease agreement for that equipment (the "June 2020 Equipment Financing"). The June 2020 Equipment Financing contains customary terms and events of default and provides for forty-eight monthly payments with an implicit interest rate of 6.1%, maturing on June 5, 2024. Upon maturity, the equipment will revert to the Intermediate Partnership.
Line of Credit. On February 19, 2021, we entered into a line of credit arrangement with a related party for $5.0 million. The line of credit has a maturity date of February 28, 2023, with an option to extend it for an additional six months and accrue interest at an annual rate of 3.50%. Interest is payable quarterly commencing March 31, 2021, and continuing each March 31, June 30, September 30 and December 31 thereafter through and including February 28, 2023. The agreement contains customary terms and events of default and is guaranteed by ARLP. We utilize the line of credit, as appropriate, for capital expenditures and investments. As of September 30, 2021, we had drawn $3.2 million under this agreement.
Other . We also have an agreement with a bank to provide additional letters of credit in an amount of $5.0 million to maintain surety bonds to secure certain asset retirement obligations and our obligations for workers' compensation benefits. On September 30, 2021, we had $5.0 million in letters of credit outstanding under this agreement.
Related-Party Transactions
We have related-party transactions and activities with Mr. Craft, MGP and their respective affiliates. These related-party transactions and activities relate principally to 1) coal mineral leases with The Joseph W. Craft III Foundation and The Kathleen S. Craft Foundation, 2) the use of aircraft, and 3) providing administrative services with respect to certain oil & gas mineral interests Mr. Craft acquired in 2019. We also have related-party transactions with (a) WKY CoalPlay, LLC ("WKY CoalPlay") regarding four mineral leases, (b) Bluegrass Minerals Management, LLC ("Bluegrass Minerals") through its noncontrolling ownership interest in our consolidated subsidiary, Cavalier Minerals and (c) with our equity interest in AllDale III. For more information regarding the Bluegrass Minerals and AllDale III, please read "Item 1. Financial Statements (Unaudited) — Note 8 – Variable Interest Entities" and " — Note 9 – Investment" of this
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Quarterly Report on Form 10-Q. We also have a line of credit with a related party as discussed in "Item 1. Financial Statements (Unaudited) — Note 7 – Long-Term Debt" of this Quarterly Report on Form 10-Q. Please read our Annual Report on Form 10-K for the year ended December 31, 2020, "Item 8. Financial Statements and Supplementary Data — Note 21 – Related-Party Transactions" for additional information concerning related-party transactions.
Other Information
Insurance
Effective October 1, 2021, we extended our existing annual property and casualty insurance program until December 1, 2021 at which time we plan to renew the program. 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 $10.0 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. 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.
Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.