ALLIANCE RESOURCE PARTNERS, L.P. 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
Our mining operations are located near many of the major eastern utility
generating plants and on major coal hauling railroads in the eastern
In 2021, we sold 32.3 million tons of coal and produced 32.2 million tons. Of
the 32.3 million tons sold, approximately two-thirds was leased from
During 2021, approximately 81.6% of our tons sold were purchased by
On
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Our results of operations could be impacted by variability in coal sales prices
in addition to prices for items that are used in coal production such as steel,
electricity and other supplies, unforeseen geologic conditions or mining and
processing equipment failures and unexpected maintenance problems, and by the
availability or reliability of transportation for coal shipments. Moreover, the
mining regulatory environment in which we operate has grown increasingly
stringent as a result of 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
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 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 acquisition and
? development of coal mineral reserves and resources using our existing
infrastructure;
? continuing to make productivity improvements to remain a low-cost producer in
each region in which we operate;
strengthening our position with existing and future customers by offering a
? broad range of coal qualities, transportation alternatives and customized
services;
developing strategic relationships to take advantage of opportunities within
? the coal and oil & gas industries and in other industries inside and outside of
the MLP sector; and
continuing to make investments in oil & gas mineral interests and coal royalty
? interests in various geographic locations within producing basins in the
continental
As of
We also have an "all other" category referred to as Other, Corporate and
Elimination. The two Coal Operations reportable segments correspond to major
coal producing regions in the eastern
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income from the leasing and development of those mineral interests. Our Coal
Royalties reportable segment includes coal mineral reserves and resources owned
or leased by
Beginning in the first quarter of 2021, we began to strategically view and
manage our coal royalty activities separately from our coal operations since
acquiring and managing a variety of royalty producing assets involve similar
attributes. As a result, we restructured our reportable segments to better
reflect this strategic view in how we manage our business and allocate
resources. Periods prior to 2021 that are presented herein have been recast to
include
mining complexes (a) the Gibson County Coal mining complex, which includes the
? Gibson South mine, (b) the Warrior mining complex, (c) the River View mining
complex and (d) the
reportable segment also includes our
The
Appalachia Coal Operations reportable segment includes currently operating
mining complexes (a) the Mettiki mining complex, (b) the
? complex and (c) the MC Mining mining complex. The Mettiki mining complex
includes
preparation plant.
Oil & Gas Royalties reportable segment includes oil & gas mineral interests
held by AR Midland and AllDale I & II and includes Alliance Minerals' equity
interests in both AllDale III and Cavalier Minerals. AR Midland acquired its
? mineral interests in the Wing Acquisition and Boulders Acquisition. Please read
"Item 8. Financial Statements and Supplementary Data-Note 3 - Acquisitions" and
"-Note 13 - Investments" of this Annual Report on Form 10-K for more
information on the Wing Acquisition and Boulders Acquisition, and AllDale III,
respectively.
Coal Royalties reportable segment includes coal mineral reserves and resources
owned or leased by
of our mining complexes in both the
? 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
pneumoconiosis liabilities,
? Partnership with its insurance requirements,
and
"Item 8. Financial Statements and Supplementary Data-Note 8 - Long-term Debt"
of this Annual Report on Form 10-K for more information on AROP Funding and
Alliance Finance.
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.
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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
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 GAAP financial measures, (i) provides additional information about our core operating performance and ability to generate and distribute cash flow, (ii) provides investors with the financial analytical framework upon which we base financial, operational, compensation and planning decisions and (iii) presents a measurement that investors, rating agencies and debt holders have indicated is useful in assessing us and our results of operations.
Segment Adjusted EBITDA. We define Segment Adjusted EBITDA (a non-GAAP financial measure) as net income attributable to ARLP before net interest expense, income taxes, depreciation, depletion and amortization, general and administrative expense, settlement gain, asset and goodwill impairments and acquisition gain. Management therefore is able to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments.
Analysis of Historical Results of Operations
2021 Compared with 2020
Total revenues increased 18.2% to
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Year Ended December 31, Year Ended December 31,
2021 2020 2021 2020
(in thousands) (per ton/BOE sold)
Coal - Tons sold 32,268 28,212 N/A N/A
Coal - Tons produced 32,207 26,990 N/A N/A
Coal - Coal sales $ 1,386,923 $ 1,232,272 $ 42.98 $ 43.68
Coal - Segment Adjusted EBITDA
Expense (1) (2) $ 975,839 $ 881,006 $ 30.24 $ 31.23
Oil & Gas Royalties - BOE sold 1,663 1,792 N/A N/A
Oil & Gas Royalties - Royalties
(3) $ 74,988 $ 42,912 $ 45.08 $ 23.95
Coal Royalties - Tons sold 20,247 18,863 N/A N/A
Coal Royalties - Intercompany
royalties $ 51,402 $ 42,112 $ 2.54 $ 2.23 For a definition of Segment Adjusted EBITDA Expense and related (1) reconciliation to its comparable GAAP financial measure, please see below
under "-Reconciliation of non-GAAP 'Segment Adjusted EBITDA Expense' to GAAP
'Operating Expenses.'"
Coal - Segment Adjusted EBITDA Expense is defined as consolidated Segment (2) 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
Production volumes increased by 19.3% in 2021, reflecting the temporary idling and scaling back of production at certain mines during 2020 in response to weak market conditions resulting from the pandemic.
Coal - Segment Adjusted EBITDA Expense. Segment Adjusted EBITDA Expense for our
coal operations increased 10.8% to
Labor and benefit expenses per ton produced, excluding workers' compensation,
decreased 11.3% to
? decrease of
to weak market conditions resulting from the pandemic.
Workers' compensation expenses per ton produced decreased to
2021 from
? resulted from increased production and refunds received in 2021 on assessments
paid to the state of
workers' compensation accrual adjustments in 2021 primarily due to unfavorable
changes in claims development.
Maintenance expenses per ton produced decreased 11.2% to
? from
primarily due to increased production volumes.
Segment Adjusted EBITDA Expense decreases above were partially offset by the following increase:
Material and supplies expenses per ton produced increased 4.9% to
ton in 2021 from
produced primarily reflects increases of
? per ton for contract labor used in the mining process and
longwall subsidence expense primarily at our
offset by decreases of
processes and
than longwall subsidence.
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Oil & gas royalties. Oil & gas royalty revenues increased to
General and administrative. General and administrative expenses for 2021
increased to
Depreciation, depletion and amortization. Depreciation, depletion and
amortization expense decreased to
Asset impairments. During 2020, we recorded
Please read "Item 8. Financial Statements and Supplementary Data- Note 5 - Goodwill Impairment."
Transportation revenues and expenses. Transportation revenues and expenses were
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Segment Information. Our 2021 Segment Adjusted EBITDA increased
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,
2021 2020 Increase (Decrease)
(in thousands)
Segment Adjusted EBITDA
Illinois Basin Coal Operations $ 265,292 $ 213,876 $ 51,416 24.0 %
Appalachia Coal Operations 172,601 171,362 1,239 0.7 %
Oil & Gas Royalties 68,774 39,773 29,001 72.9 %
Coal Royalties 33,202 23,968 9,234 38.5 %
Other, Corporate and Elimination (2) 9,383 (2,490) 11,873 (1)
Total Segment Adjusted EBITDA (3)
Coal - Tons sold Illinois Basin Coal Operations 22,264 19,113 3,151 16.5 % Appalachia Coal Operations 10,004 9,099 905 9.9 % Total tons sold 32,268 28,212 4,056 14.4 % Coal sales Illinois Basin Coal Operations$ 873,930 $ 755,208 $ 118,722 15.7 % Appalachia Coal Operations 512,993 477,064 35,929 7.5 % Total coal sales$ 1,386,923 $ 1,232,272 $ 154,651 12.6 % Other revenues Illinois Basin Coal Operations$ 4,666 $ 1,932 $ 2,734 141.5 % Appalachia Coal Operations 3,940 14,954 (11,014) (73.7) % Oil & Gas Royalties 2,197 229 1,968 (1) Coal Royalties 69 105 (36) (34.3) % Other, Corporate and Elimination 27,586 14,596 12,990 89.0 % Total other revenues$ 38,458 $ 31,816 $ 6,642 20.9 % Segment Adjusted EBITDA Expense Illinois Basin Coal Operations$ 613,303 $ 543,264 $ 70,039 12.9 % Appalachia Coal Operations 344,332 320,656 23,676 7.4 % Oil & Gas Royalties 9,943 4,106 5,837 142.2 % Coal Royalties 18,269 18,249 20 0.1 % Other, Corporate and Elimination (2) (33,198) (25,026) (8,172) (32.7) %
Total Segment Adjusted EBITDA Expense
Oil & Gas Royalties Volume - BOE (4) 1,663 1,792 (129) (7.2) % Oil & gas royalties$ 74,988 $ 42,912 $ 32,076 74.7 % Coal Royalties Volume - Tons sold (5)$ 20,247 18,863$ 1,384 7.3 % Intercompany coal royalties 51,402$ 42,112 9,290 22.1 %
(1) Percentage change not meaningful.
Other, Corporate and Elimination includes the elimination of intercompany (2) 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.
For a definition of Segment Adjusted EBITDA and related reconciliation to (3) comparable GAAP financial measures, please see below under "-Reconciliation
of non-GAAP "Segment Adjusted EBITDA" to GAAP "net income (loss)."
(4) BOE for natural gas is calculated on a 6:1 basis (6,000 cubic feet of natural
gas to one barrel).
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(5) Represents tons sold by our Coal Operations Segments associated with coal
mineral reserves leased from our Coal Royalties Segment.
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
Appalachia Coal Operations - Segment Adjusted EBITDA increased to
Oil & Gas Royalties - Segment Adjusted EBITDA increased 72.9% to
Coal Royalties - Segment Adjusted EBITDA increased 38.5% to
Other, Corporate and Elimination - Segment Adjusted EBITDA increased by
2020 Compared with 2019
Total revenues decreased 32.3% to
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Year Ended December 31, Year Ended December 31,
2020 2019 2020 2019
(in thousands) (per ton sold)
Coal - Tons sold 28,212 39,289 N/A N/A
Coal - Tons produced 26,990 39,981 N/A N/A
Coal - Coal sales $ 1,232,272 $ 1,762,442 $ 43.68 $ 44.86
Coal - Segment Adjusted EBITDA
Expense (1) (2) $ 881,006 $ 1,233,377 $ 31.23 $ 31.39
Oil & Gas Royalties - BOE sold 1,792 1,611 N/A N/A
Oil & Gas Royalties - Royalties
(3) 42,912 $ 51,735 $ 23.95 $ 32.12
Coal Royalties - Tons sold 18,863 23,002 N/A N/A
Coal Royalties - Intercompany
royalties 42,112 $ 57,737 $ 2.23 $ 2.51 For a definition of Segment Adjusted EBITDA Expense and related (1) reconciliation to its comparable GAAP financial measure, please see below
under "-Reconciliation of non-GAAP 'Segment Adjusted EBITDA Expense' to GAAP
'Operating Expenses.'"
Coal - Segment Adjusted EBITDA Expense is defined as consolidated Segment (2) 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 decreased
Coal - Segment Adjusted EBITDA Expense. Segment Adjusted EBITDA Expense for our
coal operations decreased 28.6% to
Significant cost control initiatives included the closure of higher cost per
ton production at our Dotiki and
Material and supplies expenses per ton produced decreased 8.6% to
ton in 2020 from
produced resulted primarily from production mix benefits and improved
? recoveries previously mentioned, related decreases of
support,
per ton for certain ventilation expenses, partially offset by an increase of
Maintenance expenses per ton produced decreased 13.1% to
? from
primarily due to reduced maintenance requirements as a result of production mix
benefits and improved recoveries previously mentioned.
We had no sales of outside coal purchases in 2020 compared to
? 2019. Thus, costs per ton in 2020 benefited as our cost of outside coal
purchases are generally higher on a per ton basis than our produced coal.
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Segment Adjusted EBITDA Expense decreases above were partially offset by the following increases:
Labor and benefit expenses per ton produced, excluding workers' compensation,
increased 8.7% to
? increase of
offset by an improved production mix and improved recoveries at certain mines
all previously discussed.
Production taxes and royalty expenses per ton incurred as a percentage of coal
sales prices and volumes increased
to 2019 primarily as a result of a
? the federal black lung excise tax, effective
state production mix increasing severance taxes per ton, in addition to
increased excise taxes per ton resulting from a greater mix of domestic vs.
export shipments in 2020 compared to 2019.
Oil & gas royalties. Oil & gas royalty revenues decreased to
Other revenues. Other revenues were principally comprised of
Other revenues decreased to
The decrease of
General and administrative. General and administrative expenses for 2020
decreased to
Asset impairments. During 2020, we recorded
Please read "Item 8. Financial Statements and Supplementary Data- Note 5 - Goodwill Impairment " of this Annual Report on Form 10-K.
Equity securities income. Equity securities income decreased
Acquisition gain. We recorded a non-cash acquisition gain of
Transportation revenues and expenses. Transportation revenues and expenses were
Net income attributable to noncontrolling interest. Net income attributable to
noncontrolling interest decreased to
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Segment Information. Our 2020 Segment Adjusted EBITDA decreased
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,
2020 2019 Increase (Decrease)
(in thousands)
Segment Adjusted EBITDA
Illinois Basin Coal Operations $ 213,876 $ 349,810 $ (135,934) (38.9) %
Appalachia Coal Operations 171,362 215,187 (43,825) (20.4) %
Oil & Gas Royalties 39,773 46,997 (7,224) (15.4) %
Coal Royalties 23,968 36,315 (12,347) (34.0) %
Other, Corporate and Elimination (2) (2,490) 23,692 (26,182) (110.5) %
Total Segment Adjusted EBITDA (3)
Coal - Tons sold Illinois Basin Coal Operations 19,113 28,480 (9,367) (32.9) % Appalachia Coal Operations 9,099 10,809 (1,710) (15.8) % Total tons sold 28,212 39,289 (11,077) (28.2) % Coal sales Illinois Basin Coal Operations$ 755,208 $ 1,128,588 $ (373,380) (33.1) % Appalachia Coal Operations 477,064 628,406 (151,342) (24.1) % Other, Corporate and Elimination - 5,448 (5,448) (100.0) % Total coal sales$ 1,232,272 $ 1,762,442 $ (530,170) (30.1) % Other revenues Illinois Basin Coal Operations$ 1,932 $ 13,017 $ (11,085) (85.2) % Appalachia Coal Operations 14,954 11,166 3,788 33.9 % Oil & Gas Royalties 229 1,301 (1,072) (82.4) % Coal Royalties 105 23 82 (1) Other, Corporate and Elimination 14,596 22,533 (7,937) (35.2) % Total other revenues$ 31,816 $ 48,040 $ (16,224) (33.8) % Segment Adjusted EBITDA Expense Illinois Basin Coal Operations$ 543,264 $ 791,795 $ (248,531) (31.4) % Appalachia Coal Operations 320,656 424,387 (103,731) (24.4) % Oil & Gas Royalties 4,106 7,811 (3,705) (47.4) % Coal Royalties 18,249 21,445 (3,196) (14.9) % Other, Corporate and Elimination (2) (25,026) (40,542) 15,516 38.3 %
Total Segment Adjusted EBITDA Expense
Oil & Gas Royalties Volume - BOE (4) 1,792 1,611 181 11.2 % Oil & gas royalties$ 42,912 $ 51,735 $ (8,823) (17.1) % Coal Royalties Volume - Tons sold (5) 18,863 23,002 (4,139) (18.0) % Intercompany coal royalties$ 42,112 $ 57,737 $ (15,625) (27.1) %
(1) Percentage change not meaningful.
Other, Corporate and Elimination includes the elimination of intercompany (2) 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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For a definition of Segment Adjusted EBITDA and related reconciliation to (3) comparable GAAP financial measures, please see below under "-Reconciliation
of non-GAAP "Segment Adjusted EBITDA" to GAAP "net income (loss)."
(4) BOE for natural gas is calculated on a 6:1 basis (6,000 cubic feet of natural
gas to one barrel).
(5) Represents tons sold by our Coal Operations Segments associated with coal
mineral reserves leased from our Coal Royalties Segment.
Appalachia Coal Operations - Segment Adjusted EBITDA decreased 20.4% to
Oil & Gas Royalties - Segment Adjusted EBITDA decreased to
Coal Royalties - Segment Adjusted EBITDA decreased 34.0% to
Other, Corporate and Elimination - Segment Adjusted EBITDA decreased by
Reconciliation of non-GAAP "Segment Adjusted EBITDA" to GAAP "net income (loss)" and reconciliation of non-GAAP "Segment Adjusted EBITDA Expense" to GAAP "Operating Expenses"
Segment Adjusted EBITDA (a non-GAAP financial measure) is defined as net income (loss) attributable to ARLP before net interest expense, income taxes, depreciation, depletion and amortization, asset and goodwill impairments, acquisition gain and general and administrative expenses. 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
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upon which we base financial, operational, compensation and planning decisions and (iii) presents a measurement that investors, rating agencies and debt holders have indicated is useful in assessing us and our results of operations.
Segment Adjusted EBITDA is also used as a supplemental financial measure by our management for reasons similar to those stated in the previous explanation of EBITDA. In addition, the exclusion of corporate general and administrative expenses, which are discussed above under "-Analysis of Historical Results of Operations," from consolidated Segment Adjusted EBITDA allows management to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments.
The following is a reconciliation of consolidated Segment Adjusted EBITDA to net income (loss), the most comparable GAAP financial measure:
Year Ended December 31,
2021 2020 2019
(in thousands)
Consolidated Segment Adjusted EBITDA
(70,160) (59,806) (72,997)
Depreciation, depletion and
amortization (261,377) (313,387) (309,075)
Asset impairments - (24,977) (15,190)
Goodwill impairment - (132,026) -
Interest expense, net (39,141) (45,478) (45,496)
Acquisition gain - - 177,043
Income tax (expense) benefit (417) (35) 211
Acquisition gain attributable to
noncontrolling interest - - (7,083)
Net income (loss) attributable to ARLP
598 169 7,512
Net income (loss) $ 178,755 $ (129,051) $ 406,926 Segment Adjusted EBITDA Expense (a non-GAAP financial measure) includes operating expenses, coal purchases and other income (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:
Year Ended December 31,
2021 2020 2019
(in thousands)
Segment Adjusted EBITDA Expense $ 952,649 $ 861,249 $ 1,204,896
Outside coal purchases (6,372) - (23,357)
Other income (expense) (3,020) (1,593) 561
Operating expenses (excluding
depreciation, depletion and
amortization) $ 943,257 $ 859,656 $ 1,182,100
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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 3 - Acquisitions" 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, to satisfy our contractual obligations, to fund planned capital expenditures, to service our debt obligations or to pay distributions will depend upon our future operating performance and access to and cost of financing sources, which will be affected by prevailing economic conditions generally, and in both the coal and oil & gas industries specifically, as well as other financial and business factors, some of which are beyond our control, including the COVID-19 pandemic. Based on our recent operating cash flow results, current cash position, anticipated future cash flows and sources of financing that we expect to have available, we anticipate remaining in compliance with the covenants of the Credit Agreement and expect to have sufficient liquidity to fund our operations and growth strategies. 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."
On
In
The unit repurchase program authorization does not obligate us to repurchase
any dollar amount or number of units. Since inception through
During the year ended
Cash Flows
Cash provided by operating activities was
Net cash used in investing activities was
Net cash used in financing activities was
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facility and reduced debt issuance costs in 2021, partially offset by increased payments and reduced borrowings on the securitization facility compared to 2020.
Cash Requirements
We currently estimate our 2022 annual cash requirements, including capital
expenditures, scheduled payments on long-term debt, lease obligations, asset
retirement obligation costs and workers' compensation and pneumoconiosis, to be
in a range of
We currently project average estimated annual maintenance capital expenditures
over the next five years of approximately
The availability and cost of additional capital will depend upon prevailing market conditions, the market price of our common units and several other factors over which we have limited control, as well as our financial condition and results of operations.
We use a combination of surety bonds and letters of credit to secure our
financial obligations for reclamation, workers' compensation and other
obligations as follows as of
Workers'
Reclamation Compensation
Obligation Obligation Other Total
(in millions)
Surety bonds $ 173.9 $ 68.0 $ 12.6 $ 254.5
Letters of credit - 32.3 16.8 49.1
Insurance
Effective
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 upon our consolidated financial
statements, which have been prepared in accordance with accounting principles
generally accepted in
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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
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 Wing and AllDale Acquisitions. Assets acquired and liabilities assumed are recorded at their estimated fair values at the acquisition date. The excess of purchase price over fair value of net assets acquired is recorded as goodwill. 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 Wing Acquisition, we determined a fair value for the acquired mineral
interests using a weighting of both income and market approaches. Our income
approach primarily comprised of a discounted cash flow model. The assumptions
used in the discounted cash flow model included estimated production, projected
cash flows, forward oil & gas prices and a risk-adjusted discount rate. Our
market approach consisted of the observation of acquisitions in the
For the AllDale Acquisition, in addition to valuing the acquired assets and liabilities, we were required to value our previously held equity method investments in AllDale I & II just prior to the acquisition and record a gain as the fair value was determined to be higher than the carrying value of our equity method investments. We used a discounted cash flow model to re-measure our equity method investments immediately prior to the AllDale Acquisition as well as to value the mineral interests acquired. Assumptions used in our discounted cash flow model are similar to those discussed in the Wing Acquisition above.
The only indefinite-lived intangible that the Partnership currently has is
goodwill.
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 coal sales prices. Assumptions about sales, operating margins, capital expenditures and coal sales prices are based on our budgets, business plans, economic projections, and anticipated future cash flows. 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
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We estimated the fair value of
Accordingly, we recognized an impairment charge of
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. 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:
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
20 -
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for workers' compensation of
Coal mining companies are subject to
The discount rate for workers' compensation and pneumoconiosis is derived by applying the Financial Times Stock Exchange Pension Discount Curve to the projected liability payout. Other assumptions, such as claim development patterns, mortality, disability incidence and medical costs, are based upon standard actuarial tables adjusted for our actual historical experiences whenever possible. We review all actuarial assumptions periodically for reasonableness and consistency and update such factors when underlying assumptions, such as discount rates, change or when sustained changes in our historical experiences indicate a shift in our trend assumptions are warranted.
Impairment of Long-Lived Assets
In addition to oil & gas reserves discussed above in the Oil & Gas Reserve Values section, we review the carrying value of long-lived assets and certain identifiable intangibles whenever events or changes in circumstances indicate that the carrying amount may not be recoverable based upon estimated undiscounted future cash flows. Long-lived assets and certain intangibles are not reviewed for impairment unless an impairment indicator is noted. 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, the 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 asset
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impairments of
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
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 estimates and productivity assumptions, to reflect current experience.
There were no material adjustments to the liability associated with these
assumptions for the year ended
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
Shelf Registration Statement
In
Related-Party Transactions
See "Item 8. Financial Statements and Supplementary Data-Note 21 - 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
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and Supplementary Data-Note 19 - Asset Retirement Obligations" and "-Note 20 -
Inflation
Any future inflationary or deflationary pressures could adversely affect the results of our operations. For example, at times our results have been significantly impacted by price increases affecting many of the components of our operating expenses such as fuel, steel, maintenance expense and labor.
Please see "Item 1A. 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.
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