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 income from the
production and marketing of coal to major domestic and international utilities
and industrial users as well as income from oil & gas mineral interests located
in strategic producing regions across
Our mining operations are located near many of the major eastern utility
generating plants and on major coal hauling railroads in the eastern
In 2020, we sold 28.2 million tons of coal and produced 27.0 million tons. The coal we sold in 2020 was approximately 10.6% low-sulfur coal, 51.6% medium-sulfur coal and 37.9% high-sulfur coal. Based on market expectations, we classify low-sulfur coal as coal with a sulfur content of less than 1.5%, medium-sulfur coal as coal with a sulfur content of 1.5% to 3%, and high-sulfur coal as coal with a sulfur content of greater than 3%. The Btu content of our coal ranges from 11,400 to 13,200. In 2020, approximately 98.4% of our medium- and high-sulfur coal was sold to utility plants with installed pollution control devices.
During 2020, approximately 94.2% of our tons sold were purchased by
As discussed in more detail in "Item 1A. Risk Factors," our results of operations could be impacted by variability in coal sales prices in addition to prices for items that are used in coal production such as steel, electricity and other supplies, unforeseen geologic conditions or mining and processing equipment failures and unexpected maintenance problems, and by the availability or reliability of transportation for coal shipments. Moreover, the mining regulatory environment in which we operate has grown increasingly stringent as a result of legislation and initiatives pursued during previous administrations.
Additionally, our results of operations could be impacted by our ability to
obtain and renew permits necessary for our operations, secure or acquire coal
reserves, or find replacement buyers for coal under contracts with comparable
terms to existing contracts. As outlined in "Item 1. Business-Environmental,
Health, and Safety Regulations," a variety of measures taken by regulatory
agencies in
61
Table of Contents
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 may be substantial and are often the determining factor in a coal consumer's contracting decision. The principal expenses related to our minerals interests business are production and ad valorem taxes.
Our primary business strategy is to create sustainable, capital-efficient growth in available cash to maximize the return of cash to our unitholders by:
? expanding our operations by adding and developing mines and coal reserves in
existing, adjacent or neighboring properties;
? extending the lives of our current mining operations through acquisition and
development of coal reserves using our existing infrastructure;
? continuing to make productivity improvements to remain a low-cost producer in
each region in which we operate;
strengthening our position with existing and future customers by offering a
? broad range of coal qualities, transportation alternatives and customized
services;
? developing strategic relationships to take advantage of opportunities within
the coal and oil & gas industries and MLP sector; and
? continuing to make investments in oil & gas mineral interests in various
geographic locations within producing basins in the continental
As of
(a) Gibson County Coal's mining complex, which includes the Gibson South mine,
? (b) Warrior's mining complex, (c)
our
River.
62
Table of Contents
Appalachia reportable segment includes currently operating mining complexes (a)
the Mettiki mining complex, (b) the
Mining mining complex. The Mettiki mining complex includes
? Mountain View mine and
mining complex mines reserves in both
assets, which is primarily coal mineral interests.
Minerals reportable segment includes oil & gas mineral interests held by AR
Midland and AllDale I & II, and includes Alliance Minerals equity interest in
both AllDale III and Cavalier Minerals. AR Midland acquired its mineral
? interests in the Wing Acquisition. 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 AllDale III, respectively.
Other and Corporate includes marketing and administrative activities, the
prior equity investment in Kodiak. In
equity investment. In addition, Other and Corporate includes certain Alliance
? LLC's workers' compensation and pneumoconiosis liabilities,
which assists the
("Alliance Finance"). Please read "Item 8. Financial Statements and
Supplementary Data-Note 8 - Long-term Debt" and "-Note 13 - Investments" of
this Annual Report on Form 10-K for more information on AROP Funding, Alliance
Finance and Kodiak redemption, respectively.
Market Developments and Our Response for the year ended
We began the year anticipating our results for the year ended
In response to these challenges, we halted production at all of our mining
complexes in the
During the second half of the year we saw improved economic activity, increased coal demand and some recovering oil & gas production volumes and prices which positively impacted our performance compared to the first half of the year. Higher commodity prices and lower well costs led oil & gas operators to begin bringing previously shut-in wells back online and slowly resume permitting, drilling and completion activity across the regions in which we hold mineral interests.
63
Table of Contents
Impact of the COVID-19 Pandemic
During the year 2020, a variety of measures in
As discussed above, we curtailed coal production during the year 2020 in
response to global energy demand destruction caused by the COVID-19 pandemic,
including the temporary cessation of production at various operations in both
the
To mitigate the reduced revenues from lower coal sales volumes and depressed
commodity prices impacting our minerals segment, we took numerous efforts to
optimize cash flows, reduce working capital requirements and strictly control
? capital expenditures, operating expenses and general and administrative
expenses. Our cost control initiatives during the year 2020 resulted in
significant reductions in expenses in each of these categories compared to
2019. The cost reductions are discussed in more detail below.
On
? complex and 78 employees of the
permanently.
As stated previously, the Board of Directors began suspending the cash
? distributions to unitholders with the quarter ended
continued through the quarter ended
In
? provided on
pandemic.
On
million (reducing to
? with a termination date of
revolving credit facility that was set to expire on
"Item 8. Financial Statements and Supplementary Data-Note 8 - Long-term Debt"
for more information on revolving credit facility.
? We also reduced our total debt by
our liquidity.
We are continuing to monitor and may take further actions to minimize any adverse impact caused by the COVID-19 pandemic.
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 produced; (4) Price per BOE; (5) Segment Adjusted EBITDA Expense per ton; (6) EBITDA; and (7) Segment Adjusted EBITDA.
Raw and Saleable Tons Produced per Unit Shift. We review raw and saleable tons produced per unit shift as part of our operational analysis to measure the productivity of our operating segments, which is significantly influenced by mining conditions and the efficiency of our preparation plants. Our discussion of mining conditions and preparation plant costs are found below under "-Analysis of Historical Results of Operations" and therefore provides implicit analysis of raw and saleable tons produced per unit shift.
Coal Sales Price per Ton. We define coal sales price per ton as total coal sales divided by tons sold. We review coal sales price per ton to evaluate marketing efforts and for market demand and trend analysis.
64
Table of Contents
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.
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
2020 Compared with 2019
Total revenues decreased 32.3% to
Year Ended December 31, Year Ended December 31,
2020 2019 2020 2019
(in thousands) (per ton/BOE sold)
Tons sold 28,212 39,289 N/A N/A
Tons produced 26,990 39,981 N/A N/A
Coal sales $ 1,232,272 $ 1,762,442 $ 43.68 $ 44.86
Coal - Segment Adjusted EBITDA
Expense (1) (2) $ 857,143 $ 1,197,085 $ 30.38 $ 30.47
BOE sold (3) 1,792 1,611 N/A N/A
Oil & gas royalties (4) $ 42,912 $ 51,735 $ 23.95 $ 32.12 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.'"
(2) Coal - Segment Adjusted EBITDA Expense is defined as consolidated Segment
Adjusted EBITDA Expense excluding our Minerals segment.
(3) Barrels of oil equivalent ("BOE") for natural gas volumes is calculated on a
6:1 basis (6,000 cubic feet of natural gas to one barrel).
(4) Average sales price per BOE is defined as oil & gas royalties (excluding
lease bonus revenue) divided by total BOE.
65
Table of Contents
Coal sales. Coal sales decreased
Oil & gas royalties. Oil & gas royalty revenues decreased to
Coal - Segment Adjusted EBITDA Expense. Segment Adjusted EBITDA Expense,
excluding our Minerals segment, decreased 28.4% to
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.
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.
Other revenues. Other revenues were principally comprised of
66
Table of Contents
General and administrative. General and administrative expenses for 2020
decreased to
Asset impairments. During 2020, we recorded
During 2019, we recorded an asset impairment charge of
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
67
Table of Contents
Segment Information. Our 2020 Segment Adjusted EBITDA decreased
Segment Adjusted EBITDA, tons sold, coal sales, other revenues, oil & gas
royalties, BOE volumes and Segment Adjusted EBITDA Expense by segment are as
follows:
Year Ended December 31,
2020 2019 Increase (Decrease)
(in thousands)
Segment Adjusted EBITDA
Coal - Illinois Basin $ 236,911 $ 385,200 $ (148,289) (38.5) %
Coal - Appalachia 172,288 215,950 (43,662) (20.2) %
Minerals 39,773 46,997 (7,224) (15.4) %
Other and Corporate 6,580 32,911 (26,331) (80.0) %
Elimination (9,063) (9,057) (6) (0.1) %
Total Segment Adjusted EBITDA (2)
Tons sold Coal - Illinois Basin 19,113 28,480 (9,367) (32.9) % Coal - Appalachia 9,099 10,809 (1,710) (15.8) % Other and Corporate - 564 (564) (1) Elimination - (564) 564 (1) Total tons sold 28,212 39,289 (11,077) (28.2) % Coal sales Coal - Illinois Basin$ 755,208 $ 1,128,588 $ (373,380) (33.1) % Coal - Appalachia 477,064 628,406 (151,342) (24.1) % Other and Corporate - 22,138 (22,138) (1) Elimination - (16,690) 16,690 (1) Total coal sales$ 1,232,272 $ 1,762,442 $ (530,170) (30.1) % Other revenues Coal - Illinois Basin$ 2,026 $ 13,034 $ (11,008) (84.5) % Coal - Appalachia 14,954 11,166 3,788 33.9 % Minerals 229 1,301 (1,072) (82.4) % Other and Corporate 25,124 34,712 (9,588) (27.6) % Elimination (10,517) (12,173) 1,656 13.6 % Total other revenues$ 31,816 $ 48,040 $ (16,224) (33.8) % BOE volume and oil & gas royalties Volume - BOE (3) 1,792 1,611 181 11.2 % Oil & gas royalties$ 42,912 $ 51,735 $ (8,823) (17.1) % Segment Adjusted EBITDA Expense Coal - Illinois Basin$ 520,324 $ 756,423 $ (236,099) (31.2) % Coal - Appalachia 319,730 423,623 (103,893) (24.5) % Minerals 4,106 7,811 (3,705) (47.4) % Other and Corporate 18,543 36,845 (18,302) (49.7) % Elimination (1,454) (19,806) 18,352 92.7 %
Total Segment Adjusted EBITDA Expense
(1) Percentage change not meaningful.
For a definition of Segment Adjusted EBITDA and related reconciliation to (2) comparable GAAP financial measures, please see below under "-Reconciliation
of non-GAAP "Segment Adjusted EBITDA" to GAAP "net income (loss)."
(3) BOE for natural gas is calculated on a 6:1 basis (6,000 cubic feet of natural
gas to one barrel).
The decrease of
68
Table of Contents
sales primarily reflects reduced tons sold, which decreased 32.9% compared to
2019 due to curtailed production across all of our mining operations in the
region as a result of weak coal market conditions, particularly international
markets, amid the COVID-19 pandemic. Segment Adjusted EBITDA Expense decreased
31.2% to
Appalachia - Segment Adjusted EBITDA decreased 20.2% to
Coal sales price per ton sold in 2020 decreased 9.8% compared to 2019 primarily
due to reduced metallurgical tons sold and price realizations at our Mettiki
mine. Segment Adjusted EBITDA Expense decreased 24.5% to
Minerals - Segment Adjusted EBITDA decreased to
Other and Corporate - Segment Adjusted EBITDA decreased by
2019 Compared with 2018
For discussion and analysis of 2019 compared to 2018, please refer to "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" of our Annual Report on Form 10-K for the year ended
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 attributable to ARLP before net interest expense, income taxes, depreciation, depletion and amortization, asset and goodwill impairments, acquisition gain and general and administrative expenses. Segment Adjusted EBITDA is a key component of consolidated EBITDA, which is used as a supplemental financial measure by management and by external users of our financial statements such as investors, commercial banks, research analysts and others. We believe that the presentation of EBITDA provides useful information to investors regarding our performance and results of operations because EBITDA, when used in conjunction with related GAAP financial measures, (i) provides additional information about our core operating performance and ability to generate and distribute cash flow, (ii) provides investors with the financial analytical framework upon which we base financial, operational, compensation and planning decisions and (iii) presents a measurement that investors, rating agencies and debt holders have indicated is useful in assessing us and our results of operations.
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.
69
Table of Contents
The following is a reconciliation of consolidated Segment Adjusted EBITDA to net income (loss), the most comparable GAAP financial measure:
Year Ended December 31,
2020 2019
(in thousands)
Consolidated Segment Adjusted EBITDA $ 446,489 $ 672,001
General and administrative (59,806) (72,997)
Depreciation, depletion and amortization (313,387) (309,075)
Asset impairments (24,977) (15,190)
Goodwill impairment (132,026) -
Interest expense, net (45,478) (45,496)
Acquisition gain - 177,043
Income tax (expense) benefit (35) 211
Acquisition gain attributable to noncontrolling
interest - (7,083)
Net income (loss) attributable to ARLP $ (129,220) $ 399,414
Noncontrolling interest 169 7,512
Net income (loss) $ (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,
2020 2019
(in thousands)
Segment Adjusted EBITDA Expense $ 861,249 $ 1,204,896
Outside coal purchases - (23,357)
Other income (expense) (1,593) 561
Operating expenses (excluding depreciation,
depletion and amortization) $ 859,656 $ 1,182,100
70
Table of Contents
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 and debt service obligations with cash generated from operations, cash provided by the issuance of debt or equity, borrowings under credit and securitization facilities and other financing transactions. We believe that existing cash balances, future cash flows from operations and investments, borrowings under credit facilities and cash provided from the issuance of debt or equity will be sufficient to meet our working capital requirements, capital expenditures and additional investments, debt payments, commitments and distribution payments. Nevertheless, our ability to satisfy our working capital requirements, to fund planned capital expenditures, to service our debt obligations or to pay distributions will depend upon our future operating performance and access to and cost of financing sources, which will be affected by prevailing economic conditions generally, and in both the coal and oil & gas industries specifically, as well as other financial and business factors, some of which are beyond our control, including the COVID-19 pandemic. 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."
In responding to weak market conditions, lower commodity prices, and the lockdown initiated in the first quarter of 2020 to certain areas of the global economy due to the COVID-19 pandemic, the Partnership took numerous actions to optimize cash flows and preserve liquidity by reducing capital expenditures, working capital, costs and expenses, including adjusting its corporate support structure to better align with current operating levels. We have also benefited from certain provisions of the Coronavirus Aid Relief and Economic Security Act of 2020 which modestly increased our short-term liquidity.
Additional actions to enhance our liquidity include our Board of Directors'
decisions to suspend cash distributions beginning with the quarter ended
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
Mine Development Project
In 2018, we began development of MC Mining's Excel Mine No. 5 which continued
through 2019 and into 2020. In
71
Table of Contents
Cash Flows
Cash provided by operating activities was
Net cash used in investing activities was
Net cash used in financing activities was
Contractual Obligations
We have various commitments primarily related to long-term debt, including finance and operating leases, obligations for estimated future asset retirement obligations costs, workers' compensation and pneumoconiosis, capital projects and pension funding. We expect to fund these commitments with existing cash balances, future cash flows from operations and investments as well as cash provided from borrowings of debt or issuance of equity.
The following table provides details regarding our contractual cash obligations as ofDecember 31, 2020 : Less Contractual than 1 1-3 3-5 More than Obligations Total year years years 5 years (in thousands) Long-term debt$ 603,780 $ 73,199 $ 41,041 $ 489,540 $ - Future interest obligations(1) 144,405 36,038 67,897 40,470 - Operating leases 21,858 2,346 4,306 3,368 11,838 Finance leases(2) 2,521 912 1,051 278 280 Purchase obligations for capital projects 19,667 19,667 - - - Reclamation obligations(3) 229,952 6,411 5,293 7,918 210,330 Workers' compensation and pneumoconiosis benefit(3) 294,951 11,165 18,313 14,977 250,496 Pension benefit(3) 65,634 5,629 12,223 13,108 34,674$ 1,382,768 $ 155,367 $ 150,124 $ 569,659 $ 507,618
Interest on variable-rate, long-term debt was calculated using rates
(1) effective at
borrowings.
(2) Includes amounts classified as interest.
Future commitments for reclamation obligations, workers' compensation and (3) pneumoconiosis and pension are shown at undiscounted amounts. These
obligations are primarily statutory, not contractual.
Off-Balance Sheet Arrangements
In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include coal reserve leases, indemnifications, transportation obligations and financial instruments with off-balance sheet risk, such as bank letters of credit and surety bonds. Liabilities related to these arrangements are not reflected in our consolidated
72
Table of Contents
balance sheets, and we do not expect these off-balance sheet arrangements to have any material adverse effects on our financial condition, results of operations or cash flows.
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 $ 171.1 $ 85.2 $ 16.7 $ 273.0
Letters of credit - 10.0 16.8 26.8
Capital Expenditures
Capital expenditures decreased to
We currently project average estimated annual maintenance capital expenditures
over the next five years of approximately
Insurance
Effective
Debt Obligations
Credit Facility. On
73
Table of Contents
The Credit Agreement is guaranteed by certain of our
The Credit Agreement contains various restrictions affecting the
Net restricted assets, as defined by the
Senior Notes. On
Interest is payable semi-annually in arrears on each
Accounts Receivable Securitization. On
74
Table of Contents
customary terms and events of default and provides for thirty-six monthly
payments with an implicit interest rate of 6.25%, maturing on
Other. We also have an agreement with a bank to provide additional letters of
credit in an amount of
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
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.
75
Table of Contents
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.
At
We estimated the fair value of the
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:
76
Table of Contents
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. There were no impairments of our oil & gas mineral interests during 2020.
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 -
We limit our exposure to traumatic injury claims by purchasing a high
deductible insurance policy that starts paying benefits after deductibles for a
particular claim year have been met. Our receivables for traumatic injury
claims under this policy as of
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.
77
Table of Contents
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
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.
78
Table of Contents
On at least an annual basis, we review our entire asset retirement obligation liability and make necessary adjustments for permit changes approved by state authorities, changes in the timing of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience.
Adjustments to the liability associated with these assumptions resulted in a
decrease of
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
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.
© Edgar Online, source
