Item 2. Management’s Discussion and Analysis
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THE FOLLOWING DISCUSSION UPDATES THE MD&A SECTION OF OUR 2023 ANNUAL REPORT ON FORM 10-K AND SHOULD BE READ IN CONJUNCTION THEREWITH.
Hallador Energy made significant progress in its transformation to an Independent Power Producer this quarter by signing a non-binding term sheet (“Term Sheet”) with a leading global data center developer. Our team is working diligently to finalize definitive agreements with this partner and relevant utilities that will support the delivery of our in front of the meter energy and capacity to the large hyperscaler. As we have discussed before, these types of deals are complex arrangements involving multiple parties. If we reach definitive agreements, we will have contracted large portions of our plant’s energy and capacity at much improved margins for more than a decade to come. The completion of the transaction contemplated by the Term Sheet is subject to, among other matters, the negotiation and execution of definitive agreements and there can be no assurance that definitive agreements will be entered into or that the proposed transaction will be consummated on the terms or timeframe currently contemplated, or at all.
The path to this type of long-term, higher margin transaction has been focused and deliberate. While we have not yet reached a binding agreement, we are encouraged both by the relationship with our current partner and the heavy interest that we continue to see from alternative counterparties in our energy and capacity offerings. This continued interest highlights the supply shortage in accredited capacity that we believe the MISO market is experiencing and provides the Company options in the event that we are unable to reach agreement in connection with the executed Term Sheet.
We believe accredited capacity in MISO continues to increase in value and demand, particularly in our sales region of MISO Zone 6, an area that includes Indiana and a portion of western Kentucky. This is important to Hallador based on our belief that Hallador has a significant amount of the remaining unsold accredited capacity in MISO Zone 6 over the next few years. Our current belief is guided by several factors, including:
● Demand for power is growing at the fastest rate in several decades due to new demand from data centers, electric vehicles, and onshoring of industry.
● Indiana is seeing consistent interest from data center developers, likely due to favorable Indiana tax law for datacenter development and a pro-business climate.
● Supply Response is Restricted:
o MISO has significantly reduced the capacity accreditation it awards to wind and solar generation (non-dispatchable), making it challenging to support accredited capacity needs from generating resources other than coal, U.S. natural gas (“Gas”), and nuclear (dispatchable).
o We are currently seeing minimal supply response of accredited capacity which we believe relates to the regulatory and environmental challenges for all types of baseload generation, including Gas. Additionally, we believe the muted supply response is exacerbated by the glut of solar and wind projects, which provide minimal accredited capacity, overwhelming the queue and delaying access to dispatchable generation projects that would supplement the supply of accredited capacity.
● While our data center PPA negotiations proceed, we continue to focus on improving our balance sheet and access to liquidity. During the quarter we modified our credit facility to provide the Company with short-term covenant relief to pursue additional liquidity. Subsequent to the quarter, we executed a prepaid forward power sale in the amount of $60.0 million (see “Item 1. Footnote 21 - Subsequent Events” ), delivering power from June 2025 through December 2026. A portion of the proceeds were used to pay down $20.0 million on our Term Loan, which satisfies our January 2025, April 2025, July 2025 and a portion of our October 2025 required quarterly Term Loan payments. Our October 2025 required quarterly Term Loan payment is reduced to $6.0 million as part of the $20.0 million Term Loan pay down. We also paid $34.0 million on our revolver. We did not utilize the ATM in the third quarter.
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● Quarter-over-Quarter our financial results improved. Our wholly owned subsidiary, Hallador Power, generated 1,074,000 MWh during the quarter versus 780,000 MWh in the second quarter of 2024. This is a result of stronger power pricing during the quarter and a significant decrease in Gas inventory levels against the imbalances we saw in the first half of the year. As Gas inventory decreased and prices increased, coal generation’s position in the dispatch stack improved. During the third quarter of 2024, our power plant operated more frequently than in the second quarter of 2024, partly due to having no planned maintenance, and as a result, our costs at the plant improved to $44.42 per MWh from $62.98 per MWh.
● During the third quarter, results at our Sunrise Coal subsidiary also improved in connection with the restructuring of our mining division that we undertook beginning in the first quarter of 2024 (see “Item 1. Footnote 16 – Organizational Restructuring” ). In July of 2024, we completed a project for four of our most productive units, which allowed all units to be on a split air system, which helped to improve efficiency and reduce operating costs at the mine to $66.43 per ton produced, a decrease of $1.59 from the second quarter of 2024. Sunrise Coal entered into a third-party coal contract to provide 2.5 million tons of coal from January 2026 to December 31, 2028, at an average price of $57.60 per ton.
Our goal is for Hallador Power to generate approximately 1,500,000 MWh on a quarterly basis, which equates to approximately 6,000,000 MWh annually (see Hallador Power’s capacity and utilization information below). During the nine months ended September 30, 2024, Hallador Power generated 2,670,000 MWh, or 59.3% of our target. During the first nine months of the year, we experienced sales prices of nearly $261.00 per MWh for limited times, balanced against several days of pricing below our variable cost to produce. These fluctuations led to an inconsistent dispatch schedule.
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
Power Capacity and Utilization
Nameplate capacity (MW) (i)
1,080
1,080
1,080
1,080
Accredited capacity for the period (MW) (ii)
828
864
858
899
Accredited capacity utilization (iii)
59.00
%
69.00
%
47.00
%
61.00
%
(i).
Nameplate capacity for the Merom Power Plant refers to the maximum electric output generated by the plant in the period presented and may not reflect actual production. Actual production each period varies based on weather conditions, operational conditions, and other factors.
(ii).
Accredited capacity is based on MISO’s average seasonal accreditations for the year. Average seasonal accreditations were 769 MW and 838 MW per day for 2024 and 2023, respectively. Accreditations are weighted and adjusted annually based on 3-year rolling performance metrics.
(iii).
Accredited capacity utilization is measured as power produced (MWh) divided by accredited capacity for the period (MW) multiplied by 24 times the number of days for the period.
When forward selling Capacity, we target annual sales of around $65.0 million to offset our fixed annual costs at the plant of approximately $60.0 million. We have already sold a large portion of our near term Capacity, which we believe makes our forward Capacity sales goals attainable as illustrated in our “Solid Forward Sales Position” table below.
In addition to the Term Sheet discussed above, which is not included in the graph below, our forward contracted energy sales position has a significant price increase in future years as illustrated in the graph below.
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To match Sunrise’s production levels and cost structure to that of the market demands, we restructured Sunrise operations in the first quarter of 2024. As we have previously noted, the restructuring included a reduction in force (“RIF”) of approximately 110 people in February, and we have since allowed attrition to further reduce our workforce by approximately 140 additional people, a total workforce reduction of more than 25%. We also restructured our operations to focus on our more profitable units and to idle units with higher production costs. Transitioning our Oaktown mining facilities from 7 units of production to 4 units of production was a deliberate process which took considerable time and effort, and was completed in mid-July. We are encouraged by the early results of Sunrise’s restructuring and have seen improvement in mining costs since we made the decision to adjust our operations.
The Company last reviewed its long-lived assets for impairment during the fourth quarter of 2023 and concluded no impairment was indicated. In preparing the Company’s impairment analysis, it utilizes undiscounted net cash flows over the expected life of the long-lived asset based upon anticipated production along with contracted and forward prices as well as historical operating expenses adjusted for inflation. This cash flow analysis is largely dependent upon the operating plans of the Company, which are reviewed by the Company and its Board of Directors no less than annually, normally during the fourth quarter of each year. Changes in anticipated activity levels, pricing or operating expenses can have significant effects on the ultimate value of the undiscounted cash flow analysis.
During the third quarter of 2024, the Company began a review of our mining assets and our future mining plans. This review will continue through the fourth quarter of 2024. Should the anticipated future mining activity be reduced, an impairment of our mining assets could occur. The amount of any such potential impairment, if any, is not currently estimable and will ultimately be based upon the finalized operating plans of the Company as approved by its Board of Directors, market driven pricing and cost trends, which are not known at this time. Nevertheless, the carrying amount of the Company’s mining assets is material to its condensed consolidated balance sheet at September 30, 2024 and any future impairment of such assets could therefore be material. The Company has concluded that no impairment exists as of September 30, 2024 as no triggering events have occurred during the period ended September 30, 2024.
Our condensed consolidated financial statements should be read in conjunction with this discussion. This analysis includes a discussion of metrics on a per mega-watt hour (MWh) and a per ton basis as derived from the condensed consolidated financial statements, which are considered non-GAAP measurements. These metrics are significant factors in assessing our operating results and profitability.
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OVERVIEW
I.
Q3 2024 Net Income of $1.6 million.
a. Electric Operations: During the third quarter of 2024, we sold 1,183,000 MWh representing a 41.0% increase in total MWh sold and a decrease of $10.31 in operating revenues per MWh from Q2 2024.
i. In Q3 2024, Electric Operations operating revenues were $71.9 million, or $60.78 per MWh, on a segment basis.
ii. In Q3 2024, Electric Operations operating expenses were $52.5 million, or $44.42 per MWh, which represents a decrease of $18.56 per MWh from Q2 2024.
iii. Q3 2024 Electric Operations income from operations was $16.36 per MWh, an increase of $8.25 from Q2 2024.
b. Coal Operations: During the third quarter of 2024, 0.9 million tons of coal were shipped on a segment basis during the quarter, with approximately 0.3 million tons of that being shipped to the Merom Power Plant for $16.7 million. This is an increase of 0.1 million tons of coal shipped from Q2 2024, on a segment basis.
i. In Q3 2024, Coal Operations operating revenues were $49.3 million, or $53.27 per ton, on a segment basis.
ii. In Q3 2024, Hallador’s Coal Operations operating expenses were $66.43 per ton on a segment basis, which represents a $1.59 per ton decrease from Q2 2024.
iii. We recorded a loss from operations for the quarter of $13.16 per ton on a segment basis. This is a decrease in our loss of $0.17 per ton from Q2 2024 income from operations.
II.
Q3 2024 Activity
a. Cash Flow & Debt
i. During Q3 2024, we had net cash used in operating activities of $12.9 million, and we increased our bank debt by $24.5 million.
ii. During the third quarter of 2024, we executed the First Amendment to our Credit Agreement. The primary purpose of the First Amendment was to provide us with short-term covenant relief to pursue additional liquidity. As of September 30, 2024, our bank debt was $70.0 million and our total liquidity was $34.9 million. Total liquidity is comprised of a) our additional borrowing capacity which is net of outstanding letters of credit that we are required to maintain for surety bonds and amounts drawn on our revolver, and b) cash and cash equivalents. See “Item 1. Footnote 5 – Bank Debt” .
iii. During Q3 2024, we signed a ninety-day ROFR with a potential buyer of our wholly-owned subsidiary Summit for $3.2 million. Summit is included in our “Corporate and other and eliminations” segment and primarily holds property, plant and equipment. Summit met the held-for-sale criteria and its assets were included in “assets held-for-sale” in our current assets section of our condensed consolidated balance sheets. See “Item 1. Footnote 20 – Assets Held-For-Sale” .
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III.
Solid Forward Sales Position (unaudited)
2024
2025
2026
2027
2028
2029
Total
Power
Energy
Contracted MWh (in millions)
0.81
2.56
1.83
1.78
1.09
0.27
8.34
Average contracted price per MWh
$
35.51
$
35.81
$
55.37
$
54.65
$
53.07
$
51.33
Contracted revenue (in millions)
$
28.76
$
91.67
$
101.33
$
97.28
$
57.85
$
13.86
$
390.75
Capacity
Average daily contracted capacity MW
716
801
744
623
454
100
Average contracted capacity price per MW
$
205
$
198
$
230
$
226
$
225
$
230
Contracted capacity revenue (in millions)
$
13.54
$
57.89
$
62.46
$
51.39
$
37.39
$
3.47
$
226.14
Total Energy & Capacity Revenue
Contracted Power revenue (in millions)
$
42.30
$
149.56
$
163.79
$
148.67
$
95.24
$
17.33
$
616.89
Coal
Priced tons - 3rd party (in millions)
0.66
1.78
1.50
1.50
0.50
—
5.94
Avg price per ton - 3rd party
$
48.02
$
50.04
$
56.17
$
57.17
$
59.00
$
—
Contracted coal revenue - 3rd party (in millions)
$
31.69
$
89.07
$
84.26
$
85.76
$
29.50
$
—
$
320.28
Committed and unpriced tons - 3rd party (in millions)
—
1
1
1
—
—
3
Total contracted tons - 3rd party (in millions)
0.66
2.78
2.50
2.50
0.50
—
8.94
TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED
$
73.99
$
238.63
$
248.05
$
234.43
$
124.74
$
17.33
$
937.17
Priced tons - Merom (in millions)
0.27
2.30
2.30
2.30
2.30
—
9.47
Avg price per ton - Merom
$
51.00
$
51.00
$
51.00
$
51.00
$
51.00
$
—
Contracted coal revenue - Merom (in millions)
$
13.77
$
117.30
$
117.30
$
117.30
$
117.30
$
—
$
482.97
TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT
$
87.76
$
355.93
$
365.35
$
351.73
$
242.04
$
17.33
$
1,420.14
● Actual revenue related to solid forward sales positions may differ materially for various reasons, including price adjustment features for coal quality and cost escalations, volume optionality provisions and potential force majeure events.
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LIQUIDITY AND CAPITAL RESOURCES
I.
Liquidity and Capital Resources
a. As set forth in our condensed consolidated statements of cash flows, cash provided by operations was $27.0 million and $79.5 million for the nine months ended September 30, 2024 and 2023, respectively.
b. Bank debt was reduced by $21.5 million during the nine months ended September 30, 2024. As of September 30, 2024, our bank debt was $70.0 million.
c. We expect cash generated from operations to primarily fund our capital expenditures and our debt service. As of September 30, 2024, we also had an additional borrowing capacity of $31.1 million.
d. Total liquidity as of September 30, 2024 was $34.9 million.
II.
Material Off-Balance Sheet Arrangements
a. Other than our surety bonds for reclamation, we have no material off-balance sheet arrangements. We have recorded the present value of reclamation obligations of $17.1 million, including $5.6 million at Merom, presented as asset retirement obligations (“ARO”) and accounts payable and accrued liabilities in our accompanying condensed consolidated balance sheets. In the event we are not able to perform reclamation, we have surety bonds in place totaling $30.8 million to cover ARO.
CAPITAL EXPENDITURES (capex)
For the nine months ended September 30, 2024, capex was $39.6 million allocated as follows (in millions):
Oaktown – maintenance capex
$
18.3
Oaktown – investment
4.7
Freelandville Mine
—
Merom Plant
16.1
Other
0.5
Capex per the Condensed Consolidated Statements of Cash Flows
$
39.6
RESULTS OF OPERATIONS
Presentation of Segment Information
Our operations are divided into two primary reportable segments: Electric Operations and Coal Operations. The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are presented as “Corporate and Other and Eliminations” within the Notes to the Condensed Consolidated Financial Statements and primarily are comprised of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana, which we account for using the equity method, and our held-for-sale wholly-owned subsidiary Summit Terminal LLC, a logistics transport facility located on the Ohio River.
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Electric Operations
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(in thousands)
(in thousands)
Delivered Energy
$
55,855
$
54,391
$
147,355
$
184,675
Capacity
15,860
13,012
44,506
46,137
Other
187
141
518
329
OPERATING REVENUES:
71,902
67,544
192,379
231,141
EXPENSES:
Fuel
29,602
50,652
76,522
147,032
Other operating and maintenance costs
6,176
5,727
25,958
16,640
Cost of purchased power
3,149
—
7,694
—
Utilities
91
87
316
306
Labor
7,360
7,705
22,203
23,871
Depreciation, depletion and amortization
4,802
4,695
14,197
14,045
Asset retirement obligations accretion
115
159
339
468
Exploration costs
—
—
—
—
General and administrative
1,252
1,195
3,760
3,494
Total operating expenses
52,547
70,220
150,989
205,856
INCOME (LOSS) FROM OPERATIONS
$
19,355
$
(2,676)
$
41,390
$
25,285
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(per MWh Sold)
(per MWh Sold)
MWh Generated (in thousands)
1,074
1,307
2,670
3,612
MWh Purchased (in thousands)
109
—
243
—
MWh Sold (in thousands)
1,183
1,307
2,913
3,612
Delivered Energy
$
47.21
$
41.62
$
50.59
$
51.13
Capacity
13.41
9.96
15.28
12.77
Other
0.16
0.11
0.18
0.09
OPERATING REVENUES:
60.78
51.69
66.05
63.99
EXPENSES:
Fuel
25.02
38.75
26.27
40.71
Other operating and maintenance costs
5.22
4.38
8.91
4.61
Cost of purchased power
2.66
—
2.64
—
Utilities
0.08
0.07
0.11
0.08
Labor
6.22
5.90
7.62
6.61
Depreciation, depletion and amortization
4.06
3.59
4.87
3.89
Asset retirement obligations accretion
0.10
0.12
0.12
0.13
General and administrative
1.06
0.91
1.29
0.97
Total operating expenses
44.42
53.72
51.83
57.00
INCOME (LOSS) FROM OPERATIONS:
$
16.36
$
(2.03)
$
14.22
$
6.99
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2024 vs. 2023 (third quarter)
Revenues from electric operations increased $4.4 million, or 6.5%, compared to the third quarter of 2023. While the Merom Facility ran less hours in the third quarter of 2024 compared to 2023, the contracted hours were at higher prices. We have new delivered energy contracts and capacity contracts with sales starting in 2024. We entered into three new delivered energy contracts during the current year which increased revenues by $20.9 million. We entered into three capacity contracts during 2023 that began delivery in 2024 and one new capacity contract that we entered into during the current year, which increased revenues by $10.9 million. Revenue increases from new contracts were offset by suppressed MISO pricing (~66% of total energy hours at the Merom node being priced below our production cost at our Merom Facility), and reductions in demand for Power and higher demand for Gas as Gas inventories remained high, with a continued decline in average spot pricing per MBtu of $2.11 compared to $2.59 during the same three-month period in 2023.
Fuel decreased $21.1 million, or 41.6%, compared to the third quarter of 2023. Our MWh sold decreased by 124 MWh, or 9.5%, from the third quarter of 2023. The decrease in fuel costs are primarily related to our decreased electricity sales and declines in coal market pricing. We used 0.1 million less tons of coal in our electric production compared to the third quarter of 2023. The average purchase price per ton of coal used in the plant on a segment basis, was $53.33 in the third quarter of 2024, decreasing from $76.94 per ton in the third quarter of 2023.
Cost of purchased power was $3.1 million during the third quarter of 2024. As noted above, when energy hours at the Merom Hub are priced below our production cost at our Merom Facility, we make net hourly purchases of power in the MISO market.
Income from operations increased $22.0 million, or 823.3%, and increased $18.39 per MWh, from the three months ended September 30, 2023. The main drivers of this change in income from operations are described in the discussion above.
2024 vs. 2023 (nine months)
Delivered energy revenues from electric operations decreased $37.3 million, or 20.2%, compared to the nine months ended September 30, 2023 due to suppressed MISO pricing (~75% of total energy hours at the Merom Hub being priced below our production cost at our Merom Facility), reductions in demand for Power and higher demand for Gas as Gas inventories remained high with a continued decline in average spot pricing per MBtu of $2.11 compared to $2.47 during the same nine-month period in 2023.
Fuel decreased $70.5 million, or 48.0%, compared to the nine months ended September 30, 2023. Production decreased by 942 MWh, or 26.1%, from the first nine months of 2023. The decrease in fuel costs are due to the expiration of a coal purchase contract in June of 2023 and declines in coal market pricing. We used 0.5 million less tons of coal in our electric production compared to the nine months ended September 30, 2023. The average purchase price per ton of coal used in the plant on a segment basis, was $54.83 for the nine months ended September 30, 2024, decreasing from $62.37 during the nine months ended September 30, 2023. As discussed above, average spot prices for Gas were down per MMBtu decreasing the demand for Electric Power.
Cost of purchased power was $7.7 million during the first nine months of 2024. As noted above, when energy hours at the Merom Hub are priced below our production cost at our Merom Facility, we make net hourly purchases of power in the MISO market.
Other operating and maintenance costs increased $9.3 million, or 56.0%, compared to the nine months ended September 30, 2023 primarily due to our planned maintenance outage during the second quarter of 2024 which resulted in $7.0 million in additional costs for the period.
Income from operations increased $16.1 million, or 63.7%, and increased $7.23 per MWh, from the nine months ended September 30, 2023. The main drivers of this change in income from operations are described in the discussion above.
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Coal Operations
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(in thousands)
(in thousands)
OPERATING REVENUES:
$
49,331
$
134,896
$
162,630
$
343,267
EXPENSES:
Fuel
572
1,537
2,557
5,712
Other operating and maintenance costs
27,031
59,700
80,419
122,882
Utilities
3,094
4,421
10,639
13,041
Labor
19,361
29,934
66,241
90,827
Depreciation, depletion and amortization
9,013
11,508
28,671
37,249
Asset retirement obligations accretion
295
309
869
912
Exploration costs
62
171
179
682
General and administrative
2,082
2,552
8,012
7,747
Total operating expenses
61,510
110,132
197,587
279,052
INCOME (LOSS) FROM OPERATIONS
$
(12,179)
$
24,764
$
(34,957)
$
64,215
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(per ton)
(per ton)
Tons Sold (in thousands)
926
2,054
2,989
5,461
OPERATING REVENUES:
$
53.27
$
65.67
$
54.41
$
62.86
EXPENSES:
Fuel
0.62
0.75
0.86
1.05
Other operating and maintenance costs
29.19
29.07
26.90
22.50
Utilities
3.34
2.15
3.56
2.39
Labor
20.91
14.57
22.16
16.63
Depreciation, depletion and amortization
9.73
5.60
9.59
6.82
Asset retirement obligations accretion
0.32
0.15
0.29
0.17
Exploration costs
0.07
0.08
0.06
0.12
General and administrative
2.25
1.24
2.68
1.42
Total operating expenses
66.43
53.61
66.10
51.10
INCOME (LOSS) FROM OPERATIONS:
$
(13.16)
$
12.06
$
(11.69)
$
11.76
2024 vs. 2023 (third quarter)
Segment operating revenues from coal operations decreased $85.6 million, or 63.4%, from the third quarter of 2023. Consolidated operating revenues from coal operations decreased $65.2 million, or 66.6%, from the third quarter of 2023. These declines were due to reductions in volume and average sales price for our coal. Our average sales price, on a segment basis, decreased $12.40 per ton and we sold 1.1 million tons less compared to the third quarter of 2023. Our average sales price on a consolidated basis decreased $7.91 per ton and we sold 1.0 million tons less compared to the third quarter of 2023. Operating revenues for the third quarter of 2024 include $16.7 million in sales to the Merom plant which were eliminated in the consolidation.
Other operating and maintenance costs decreased $32.7 million, or 54.7%, and labor decreased $10.6 million, or 35.3%, from the third quarter of 2023. These changes were driven by impacts from the Reorganization Plan disclosed in “Item 1. Note 16 — Organizational Restructuring” to the Condensed Consolidated Financial Statements. During the third quarter 2024, underground costs such as roof support and belt maintenance, fuel and utilities, as well as maintenance costs all had significant decreases in comparison to the third quarter of 2023. We produced 0.7 million tons less in the third quarter of 2024 than the third quarter of 2023.
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Depreciation, depletion, and amortization decreased $2.5 million, or 21.7%, from the third quarter of 2023 due to decreases in coal production and the remaining useful lives of the mine development assets.
Income (loss) from operations decreased $36.9 million, or 149.2%, and decreased $25.22 per ton, from the three months ended September 30, 2023. The main drivers of this change in income (loss) from operations are described in the discussion above.
2024 vs. 2023 (nine months)
Segment operating revenues from coal operations decreased $180.6 million, or 52.6%, from the nine months ended September 30, 2023. Consolidated operating revenues from coal operations decreased $166.0 million, or 58.7%, from the nine months ended September 30, 2023. These declines were due to reductions in volume and average sales price for our coal. Our average sales price, on a segment basis, decreased $8.45 per ton and we sold 2.5 million tons less compared to the first nine months of 2023. Our average sales price, on a consolidated basis, for the first nine months of 2024, decreased $4.63 per ton and we sold 2.6 million tons less compared to the first nine months of 2023.
Other operating and maintenance costs decreased $42.5 million, or 34.6%, and labor decreased $24.6 million, or 27.1%, from the nine months ended September 30, 2023. These changes were driven by the Reorganization Plan disclosed in “Item 1. Note 16 — Organizational Restructuring” to the Condensed Consolidated Financial Statements. During the first nine months of 2024, we produced 2.3 million tons less on a segment basis than the first nine months of 2023. Additionally, we went from 5 mines producing to 1 mine producing and reduced our coal employee headcount by 313 employees as part of the Reorganization Plan.
Depreciation, depletion, and amortization decreased $8.6 million, or 23.0%, from the nine months ended September 30, 2023 due to decreases in coal production and the remaining useful lives of the mine development assets.
Income (loss) from operations decreased $99.2 million, or 154.4%, and decreased $23.45 per ton, from the nine months ended September 30, 2023. The main drivers of this change in income from operations are described in the discussion above.
Quarterly coal sales and cost data on a segment basis are as follows (in thousands, except per ton data and wash plant recovery percentage):
All Mines
4th 2023
1st 2024
2nd 2024
3rd 2024
T4Qs
Tons produced
1,331
1,271
889
873
4,364
Tons sold
1,461
1,214
849
926
4,450
Wash plant recovery in %
62
%
60
%
59
%
60
%
Capex
$
17,867
$
8,632
$
7,560
$
6,810
$
40,869
Maintenance capex
$
13,567
$
8,085
$
6,014
$
4,208
$
31,874
Maintenance capex per ton sold
$
9.29
$
6.66
$
7.08
$
4.54
$
7.16
All Mines
4th 2022
1st 2023
2nd 2023
3rd 2023
T4Qs
Tons produced
1,721
2,006
1,723
1,594
7,044
Tons sold
1,664
1,693
1,714
2,054
7,125
Wash plant recovery in %
68
%
70
%
67
%
65
%
Capex
$
12,368
$
12,639
$
14,445
$
11,570
$
51,022
Maintenance capex
$
5,748
$
7,778
$
9,754
$
7,938
$
31,218
Maintenance capex per ton
$
3.45
$
4.59
$
5.69
$
3.86
$
4.38
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Presentation of Consolidated Information
EARNINGS (LOSS) PER SHARE
4th 2023
1st 2024
2nd 2024
3rd 2024
Basic
$
(0.31)
$
(0.05)
$
(0.27)
$
0.04
Diluted
$
(0.31)
$
(0.05)
$
(0.27)
$
0.04
4th 2022
1st 2023
2nd 2023
3rd 2023
Basic
$
0.91
$
0.67
$
0.51
$
0.49
Diluted
$
0.83
$
0.61
$
0.47
$
0.44
INCOME TAXES
Our effective tax rate (ETR) is estimated at ~24% and ~13% for the nine months ended September 30, 2024 and 2023, respectively. For the nine months ended September 30, 2024, we recorded income taxes using an estimated annual effective tax rate based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate. Our ETR differs from the statutory rate due primarily to statutory depletion in excess of tax basis and changes in the valuation allowance. The deduction for statutory percentage depletion does not necessarily change proportionately to changes in income (loss) before income taxes.
RESTRICTED STOCK GRANTS
See “Item 1. Financial Statements - Note 9 - Stock Compensation Plans” for a discussion of RSUs.
CRITICAL ACCOUNTING ESTIMATES
We believe that the estimates of coal reserves, asset retirement obligation liabilities, deferred tax accounts, valuation of inventory, and the estimates used in impairment analysis are our critical accounting estimates.
The reserve estimates are used in the depreciation, depletion, and amortization calculations and our internal cash flow projections. If these estimates turn out to be materially under or over-stated, our depreciation, depletion and amortization expense and impairment test may be affected. The process of estimating reserves is complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. The reserve estimates are prepared by professional engineers, both internal and external, and are subject to change over time as more data becomes available. Changes in the reserves estimates from the prior year were nominal.
SMCRA and similar state statutes require, among other things, that surface disturbance be restored in accordance with specified standards and approved reclamation plans. SMCRA requires us to restore affected surface areas to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations.
Obligations are reflected at the present value of their future cash flows. We reflect accretion of the obligations for the period from the date they are incurred through the date they are extinguished. The ARO assets are amortized using the units-of-production method over estimated recoverable (proven and probable) reserves. We use credit-adjusted risk-free discount rates ranging from 7% to 10% to discount the obligation, inflation rates anticipated during the time to reclamation, and cost estimates prepared by its engineers inclusive of market risk premiums. Activities include reclamation of pit and support acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and slurry ponds.
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Accretion expense is recognized on the obligation through the expected settlement date. On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing and extent of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Any difference between the recorded amount of the liability and the actual cost of reclamation will be recognized as a gain or loss when the obligation is settled.
We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. We believe that our income tax filing positions and deductions would be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position. We have not taken any significant uncertain tax positions, and our tax provisions and returns are prepared by a large public accounting firm with significant experience in energy related industries. Changes to the estimates from reported amounts in the prior year were not significant.
Inventory is valued at a lower of cost or net realizable value (NRV). Anticipated utilization of low sulfur, higher-cost coal from our Freelandville, and Prosperity mines has the potential to create NRV adjustments as our estimated needs change. The NRV adjustments are subject to change as our costs may fluctuate due to higher or lower production and our NRV may fluctuate based on sales contracts we enter into from time to time. As of September 30, 2024, and December 31, 2023, coal inventory includes NRV adjustments of $1.8 million and $2.0 million, respectively.
Long-lived assets used in operations are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The determination of the lowest level of cash flows is largely based on nature of production, common infrastructure, common sales points, common regulation and management oversight to make such determinations. These determinations could impact the determination and measurement of a potential asset impairment. This cash flow analysis is largely dependent upon the operating plans of the Company, which are reviewed by the Company and its Board of Directors no less than annually, normally during the 4 th quarter of each year. Changes in anticipated activity levels, pricing or operating expenses can have significant effects on the ultimate value of the undiscounted cash flow analysis.
During the third quarter of 2024, the Company began a review of its Oaktown mining facilities and future mining plan related to this complex. This review will continue through the fourth quarter of 2024. Should the anticipated future mining activity related to the Company’s Oaktown mining facilities be reduced, an impairment of certain mining assets could occur. The amount of any such potential impairment, if any, is not currently estimable and will ultimately be based upon the finalized operating plans of the Company as approved by its Board of Directors, market driven pricing and cost trends, which are not known at this time. Nevertheless, the carrying amount of the Company’s mining assets is material to its condensed consolidated balance sheet at September 30, 2024 and any future impairment of such assets could therefore be material.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
No material changes from the disclosure in our 2023 Annual Report on Form 10-K .
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Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.