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 2019, we sold 39.3 million tons of coal and produced 40.0 million tons. The coal we sold in 2019 was approximately 26.2% low-sulfur coal, 65.2% medium-sulfur coal and 8.6% 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.
During 2019, approximately 78.8% of our tons sold were purchased by
On
The AllDale and Wing Acquisitions provide us with diversified exposure to industry leading operators and are consistent with our general business strategy to grow our oil & gas mineral interest business. For more information on these transactions, please read "Item 8. Financial Statement and Supplemental Data-Note 3 - Acquisitions" and "-Note 12 - Investments".
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
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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
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, as outlined in "Item 1. Business-Regulation of the Oil & Gas Industry". 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
As a result of the AllDale Acquisition, we now control the underlying oil & gas
mineral interests held by AllDale I & II. This control over the oil & gas
mineral interests held by AllDale I & II reflects a strategic change in how we
manage our business and how resources are allocated by our chief operating
decision maker. Due to this strategic change, we realigned our reportable
segments in the first quarter of 2019 to include our oil & gas mineral interests
within a new Minerals reportable segment. The mineral interests acquired through
the Wing Acquisition in
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segment rather than Other and Corporate to better reflect our
Gibson County Coal's mining complex, which includes the Gibson North and
South mines, (b) Warrior's mining complex, (c)
? (d) the
includes our operating Mt. Vernon coal loading terminal in
River. The Gibson North mine was idled in the fourth quarter of 2019 in
response to market conditions.
Appalachia reportable segment includes our operating mining complexes (a) the
Mettiki mining complex, (b) the
? Mining mining complex. The Mettiki mining complex includes
Mountain View mine and
reportable segment also includes
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.
Other and Corporate marketing and administrative activities include the Matrix
Group, Alliance Coal's coal brokerage activity and Alliance Minerals' prior
equity investment in Kodiak. In
investment. In addition, Other and Corporate includes certain
? Properties' land and mineral interest activities,
compensation and pneumoconiosis liabilities,
the
("AROP Funding") and
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 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.
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.
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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 impairment 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
2019 Compared with 2018
We reported net income attributable to ARLP of
Year Ended December 31, Year Ended December 31,
2019 2018 2019 2018
(in thousands) (per ton sold)
Tons sold 39,289 40,421 N/A N/A
Tons produced 39,981 40,266 N/A N/A
Coal sales $ 1,762,442 $ 1,844,808 $ 44.86 $ 45.64
Oil & gas royalties $ 51,735 $ - N/A N/A
Coal - Segment Adjusted EBITDA
Expense (1) (2) $ 1,197,085 $ 1,211,800 $ 30.47 $ 29.98 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.
Coal sales. Coal sales decreased
Oil & gas royalties. Our mineral interests contributed oil & gas royalties of
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Coal - Segment Adjusted EBITDA Expense. Segment Adjusted EBITDA Expense,
excluding our Minerals segment, decreased 1.2% to
Labor and benefit expenses per ton produced, excluding workers' compensation,
? increased 6.2% to
increase of
production volumes;
Workers' compensation expenses per ton produced increased to
? 2019 from
resulted from the impact of lower discount rates and higher actuarial accrual
adjustments due primarily to unfavorable changes in claims development;
Maintenance expenses per ton produced increased 4.1% to
? from
primarily due to reduced sales and production volumes at certain mines
discussed above; and
Outside coal purchases increased
? from purchased coal, which generally cost higher on a per ton basis than our
produced coal.
Segment Adjusted EBITDA Expense increases above were partially offset by the following decrease:
Production taxes, royalties and other selling expenses are primarily based on
? coal volumes and a percentage of coal sales prices. These expenses decreased
favorable state sales mix and lower excise tax rates in 2019.
Depreciation, depletion and amortization. Depreciation, depletion and
amortization expense increased to
Settlement gain. During 2018, we finalized an agreement with a customer and
certain of its affiliates to settle litigation we initiated in 2015. The
agreement provided for a
Asset impairment. We recognized a non-cash asset impairment charge of
Equity method investment income. Equity method investment income decreased to
Acquisition gain. We were required to re-measure Cavalier Minerals' equity
method investments in AllDale I & II to fair value as a result of the AllDale
Acquisition. The re-measurement resulted in a gain of
Please read ""Item 8. Financial Statements and Supplementary Data-Note 3 - Acquisitions" for more information on the acquisition gain in connection with the AllDale Acquisition.
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Transportation revenues and expenses. Transportation revenues and expenses were
Net income attributable to noncontrolling interest. Net income attributable to
noncontrolling interest increased to
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Segment Information. Our 2019 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,
2019 2018 Increase (Decrease)
(in thousands)
Segment Adjusted EBITDA
Coal - Illinois Basin $ 385,200 $ 417,773 $ (32,573) (7.8) %
Coal - Appalachia 215,950 240,286 (24,336) (10.1) %
Minerals 46,997 21,323 25,674 120.4 %
Other and Corporate 32,911 44,864 (11,953) (26.6) %
Elimination (9,057) (8,555) (502) (5.9) %
Total Segment Adjusted EBITDA (2)
Tons sold Coal - Illinois Basin 28,480 30,055 (1,575) (5.2) % Coal - Appalachia 10,809 10,364 445 4.3 % Other and Corporate 564 994 (430) (43.3) % Elimination (564) (992) 428 43.1 % Total tons sold 39,289 40,421 (1,132) (2.8) % Coal sales Coal - Illinois Basin$ 1,128,588 $ 1,197,143 $ (68,555) (5.7) % Coal - Appalachia 628,406 635,530 (7,124) (1.1) % Other and Corporate 22,138 43,393 (21,255) (49.0) % Elimination (16,690) (31,258) 14,568 46.6 % Total coal sales$ 1,762,442 $ 1,844,808 $ (82,366) (4.5) % Other revenues Coal - Illinois Basin$ 13,034 $ 16,999 $ (3,965) (23.3) % Coal - Appalachia 11,166 3,000 8,166 (1) Minerals 1,301 - 1,301 (1) Other and Corporate 34,712 38,096 (3,384) (8.9) % Elimination (12,173) (12,431) 258 2.1 % Total other revenues$ 48,040 $ 45,664 $ 2,376 5.2 % BOE volume and oil & gas royalties Volume - BOE (3) 1,611 - 1,611 (1) Oil & gas royalties$ 51,735 $ -$ 51,735 (1) Segment Adjusted EBITDA Expense Coal - Illinois Basin$ 756,423 $ 796,370 $ (39,947) (5.0) % Coal - Appalachia 423,623 398,243 25,380 6.4 % Minerals 7,811 - 7,811 (1) Other and Corporate 36,845 52,321 (15,476) (29.6) % Elimination (19,806) (35,134) 15,328 43.6 %
Total Segment Adjusted EBITDA Expense
(1) Percentage change not meaningful.
For a definition of Segment Adjusted EBITDA and related reconciliation to its (2) comparable GAAP financial measure, please see below under "-Reconciliation of
non-GAAP "Segment Adjusted EBITDA" to GAAP "net income."
(3) BOE for natural gas is calculated on a 6:1 basis (6,000 cubic feet of natural
gas to one barrel).
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the cessation of production at our Dotiki mine in 2019 to focus on shifting
production to our lower-cost mines, offset in part by additional production
units at the River View mine. Segment Adjusted EBITDA Expense decreased 5.0% to
Appalachia - Segment Adjusted EBITDA decreased 10.1% to
Segment Adjusted EBITDA Expense per ton increased 2.0% to
Minerals - Segment Adjusted EBITDA increased to
Other and Corporate - Segment Adjusted EBITDA decreased by
2018 Compared with 2017
We reported net income attributable to ARLP of
EPU for 2018 reflects the impact of the Simplification Transactions eliminating
general partner net income allocations to MGP beginning with the second quarter
of 2018. EPU for 2017 reflects the impact of the Exchange Transaction
eliminating general partner net income allocations associated with the IDRs and
a 0.99% general partner interest in ARLP, both of which were held by MGP prior
to the Exchange Transaction. MGP exchanged both its general partner interest
and IDRs for a non-economic general partner interest and significant limited
partner units beginning with distributions for the second quarter of 2017. See
"Item 1. Business-Partnership Simplification" for more information on the
Exchange Transaction and Simplification Transactions. For the time between the
Exchange Transaction and the Simplification Transactions, MGP maintained a
1.0001% general partner interest in the
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the Exchange Transaction and Simplification Transactions on EPU, including a table providing a reconciliation of Pro Forma EPU amounts to net income of ARLP.
Year Ended December 31, Year Ended December 31,
2018 2017 2018 2017
(in thousands) (per ton sold)
Tons sold 40,421 37,824 N/A N/A
Tons produced 40,266 37,609 N/A N/A
Coal sales $ 1,844,808 $ 1,711,114 $ 45.64 $ 45.24
Coal - Segment Adjusted EBITDA
Expense (1) (2) $ 1,211,800 $ 1,092,187 $ 29.98 $ 28.88 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.
Coal sales. Coal sales increased
Coal - Segment Adjusted EBITDA Expense. Segment Adjusted EBITDA Expense,
excluding our Minerals segment, increased 11.0% to
On a per ton basis, Segment Adjusted EBITDA Expense increased 3.8% to
Labor and benefit expenses per ton produced, excluding workers' compensation,
? increased 1.6% to
increase of
expenses at various mines; and
Material and supplies expenses per ton produced increased 13.1% to
ton in 2018 from
? resulted primarily from increases of
ton for contract labor used in the mining process and
and fuel used in the mining process.
Segment Adjusted EBITDA Expense per ton increases discussed above were partially offset by the following decrease:
Production taxes, royalties and other selling expenses incurred as a percentage
of coal sales prices and volumes decreased
? compared to 2017 primarily as a result of a favorable state sales mix,
increased sales into the export market and lower average coal sales prices in
the
in Appalachia.
General and administrative. General and administrative expenses for 2018
increased to
Depreciation, depletion and amortization. Depreciation, depletion and
amortization expense increased to
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Settlement gain. During 2018, we finalized an agreement with a customer and
certain of its affiliates to settle litigation we initiated in 2015. The
agreement provided for a
Asset impairment. We recognized
Equity method investment income. Equity method investment income increased to
Equity securities income. Equity securities income increased
Debt extinguishment loss. We recognized a debt extinguishment loss of
Transportation revenues and expenses. Transportation revenues and expenses were
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Segment Information. Our 2018 Segment Adjusted EBITDA increased 4.9% to
Year Ended December 31,
2018 2017 Increase (Decrease)
(in thousands)
Segment Adjusted EBITDA
Coal - Illinois Basin $ 417,773 $ 398,080 $ 19,693 4.9 %
Coal - Appalachia 240,286 234,124 6,162 2.6 %
Minerals 21,323 13,297 8,026 60.4 %
Other and Corporate 44,864 45,296 (432) (1.0) %
Elimination (8,555) (8,769) 214 2.4 %
Total Segment Adjusted EBITDA (1)
Tons sold Coal - Illinois Basin 30,055 27,026 3,029 11.2 % Coal - Appalachia 10,364 10,783 (419) (3.9) % Other and Corporate 994 1,636 (642) (39.2) % Elimination (992) (1,621) 629 38.8 % Total tons sold 40,421 37,824 2,597 6.9 % Coal sales Coal - Illinois Basin$ 1,197,143 $ 1,078,255 $ 118,888 11.0 % Coal - Appalachia 635,530 616,305 19,225 3.1 % Other and Corporate 43,393 74,973 (31,580) (42.1) % Elimination (31,258) (58,419) 27,161 46.5 % Total coal sales$ 1,844,808 $ 1,711,114 $ 133,694 7.8 % Other revenues Coal - Illinois Basin$ 16,999 $ 12,024 $ 4,975 41.4 % Coal - Appalachia 3,000 3,621 (621) (17.1) % Other and Corporate 38,096 39,776 (1,680) (4.2) % Elimination (12,431) (12,015) (416) (3.5) % Total other revenues$ 45,664 $ 43,406 $ 2,258 5.2 % Segment Adjusted EBITDA Expense Coal - Illinois Basin$ 796,370 $ 692,199 $ 104,171 15.0 % Coal - Appalachia 398,243 385,802 12,441 3.2 % Other and Corporate 52,321 75,851 (23,530) (31.0) % Elimination (35,134) (61,665) 26,531 43.0 %
Total Segment Adjusted EBITDA Expense
For a definition of Segment Adjusted EBITDA and related reconciliation to its (1) comparable GAAP financial measure, please see below under "-Reconciliation of
non-GAAP "Segment Adjusted EBITDA" to GAAP "net income."
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previously mentioned difficult mining conditions in addition to increased roof support and contract labor costs per ton at various mines and start-up costs associated with reopening the Gibson North mine in 2018.
Appalachia - Segment Adjusted EBITDA increased 2.6% to
Minerals - Segment Adjusted EBITDA increased to
Other and Corporate - Coal sales and Segment Adjusted EBITDA Expense decreased
by
Reconciliation of non-GAAP "Segment Adjusted EBITDA" to GAAP "net income" 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, settlement gain, asset impairment, acquisition gain, debt extinguishment loss 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.
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The following is a reconciliation of consolidated Segment Adjusted EBITDA to net income, the most comparable GAAP financial measure:
Year Ended December 31,
2019 2018 2017
(in thousands)
Consolidated Segment Adjusted EBITDA
(72,997) (68,298) (61,760)
Depreciation, depletion and
amortization (309,075) (280,225) (268,981)
Settlement gain - 80,000 -
Asset impairment (15,190) (40,483) -
Interest expense, net (45,496) (40,059) (39,291)
Acquisition gain 177,043 - -
Debt extinguishment loss - - (8,148)
Income tax (expense) benefit 211 (22) (210)
Acquisition gain attributable to
noncontrolling interest (7,083) - -
Net income attributable to ARLP $ 399,414 $ 366,604 $ 303,638
Noncontrolling interest 7,512 866 563
Net income $ 406,926 $ 367,470 $ 304,201 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,
2019 2018 2017
(in thousands)
Segment Adjusted EBITDA Expense $ 1,204,896 $ 1,211,800 $ 1,092,187
Outside coal purchases (23,357) (1,466) -
Other income (expense) 561 (2,621) (332)
Operating expenses (excluding
depreciation, depletion and
amortization) $ 1,182,100 $ 1,207,713 $ 1,091,855
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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 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. Based on our recent operating results, current cash position, current unitholder distributions, anticipated future cash flows and sources of financing that we expect to have available, we do not anticipate any constraints to our liquidity at this time.
However, to the extent operating cash flow or access to and cost of financing sources are materially different than expected, future 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
Please read "Part II - Item 5. Market for Registrant's Common Equity, Related
Unitholder Matters and Issuer Purchases of
Mine Development Project
In 2018, we began development of MC Mining's Excel Mine No. 5 and continued in
2019. We currently anticipate deploying capital of approximately
Cash Flows
Cash provided by operating activities was
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certain of its affiliates initiated in 2015. In addition, decreases in cash provided by operating activities for 2019 resulted from lower net income in 2019 after excluding the 2019 non-cash acquisition gain and the non-cash impairments in both years. Additional decreases in 2019 were due to unfavorable working capital changes related to inventories, accounts payable and payroll and related benefit accruals. These decreases were partially offset by a favorable working capital change related to trade receivables.
Net cash used in investing activities was
Net cash used in financing activities was
We have various commitments primarily related to long-term debt, including capital 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, 2019 : Less Contractual than 1 1-3 3-5 More than Obligations Total year years years 5 years (in thousands) Long-term debt$ 789,280 $ 13,157 $ 355,051 $ 21,072 $ 400,000 Future interest obligations(1) 184,479 46,179 67,714 60,641 9,945 Operating leases 25,728 3,832 4,497 3,860 13,539 Finance leases(2) 11,268 8,747 1,824 278 419 Purchase obligations for capital projects 28,633 28,633 - - - Reclamation obligations(3) 240,463 4,496 5,370 5,013 225,584 Workers' compensation and pneumoconiosis benefit(3) 303,648 11,923 18,794 15,079 257,852 Pension benefit(3) 64,614 5,288 11,722 12,849 34,755$ 1,648,113 $ 122,255 $ 464,972 $ 118,792 $ 942,094
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 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.
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We use a combination of surety bonds and letters of credit to secure our
financial obligations for reclamation, workers' compensation and other
obligations as follows as of
Workers'
Reclamation Compensation
Obligation Obligation Other Total
(in millions)
Surety bonds $ 181.6 $ 82.2 $ 15.8 $ 279.6
Letters of credit - 8.0 6.3 14.3
Capital Expenditures
Capital expenditures increased to
We currently project average estimated annual maintenance capital expenditures
over the next five years of approximately
Insurance
Effective
Debt Obligations
Credit Facility. On
The Credit Agreement is guaranteed by all of the material direct and indirect
subsidiaries of our
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We utilize the Revolving Credit Facility, as appropriate, for working capital requirements, capital expenditures and investments, scheduled debt payments and distribution payments.
The Credit Agreement contains various restrictions affecting our
Senior Notes. On
Interest is payable semi-annually in arrears on each
Accounts Receivable Securitization. On
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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 preliminary 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 recent 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. At
We have assessed the reporting unit definitions and determined that at
The Partnership computes the fair value of these 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. There were no impairments of goodwill during 2019 or 2018.
In future periods, it is reasonably possible that a variety of circumstances could result in an impairment of our goodwill.
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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 were required to make significant
judgments and estimates regarding the impact of anticipated economic factors on
our business. The forecast assumptions used in the period ended
Our estimates of fair value are sensitive to changes in all of these 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.
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 prepared 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 reserves 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 2019.
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
19 -
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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 FSTE 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, the asset is monitored by management where changes
to significant assumptions are reviewed. 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. 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
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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.
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
Universal Shelf
In
Related-Party Transactions
See "Item 8. Financial Statements and Supplementary Data-Note 20 - 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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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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