HALLADOR ENERGY CO 10-Q

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 is on a strategic and deliberate path to transform our company and capture increased value from our products and services as we advance up the value chain by expanding our offerings from fuel production to wholesale electricity sales to powering the industrial end user. For many years, our Sunrise Coal subsidiary was our primary asset, producing fuel to sell to third-party customers. In the fourth quarter of 2022, we acquired the Merom Power Plant through our Hallador Power Company (“Hallador Power” or “HPC”) subsidiary enabling us the ability to convert the majority of our fuel production into wholesale electricity and capacity, which traditionally sells at higher margins than coal. As part of this process, we issued $29.0 million of convertible debt in 2022 to improve our capital position and facilitate the acquisition of the Merom Power Plant.  In 2022, $10.0 million of these convertible notes were converted to equity and the remaining balance was converted in the first half of 2024. Looking at the wholesale electric sales we have made since the acquisition of the Merom Power Plant, along with the prices indicated by the forward power curves, we believe that HPC has the potential to achieve gross profit margins greater than the margins we have historically seen in coal sales.  In the first quarter of this year, our sales to third-party customers from electricity exceeded those of our sales from coal. In connection with this shift in company focus, we changed our SIC code from 1220 bituminous coal producer to 4911 electric services during the second quarter. Additionally, in the first quarter of this year we announced the signing of a Memorandum of Understanding (“MOU”) with Hoosier Energy and WIN REMC that provides a pathway to facilitate sales of our electricity to industrial end users of power. As we continue to transform our product offerings from fuel to wholesale electricity, to supplying power to higher value end-users, we believe we can achieve increasingly higher gross profit margins. The recent environment for spot electricity sales has been challenging. This past winter, record high U.S. natural gas (“Gas”) production ran into the ninth warmest winter on record according to National Oceanic and Atmospheric Administration.  The lack of winter heating demand caused Gas inventory levels to climb as much as 38% above the 5-year average.  As Gas prices adjusted downward to encourage the market to consume excess Gas inventory, wholesale electric (“Energy”) prices also declined.  In the first six months of 2024, approximately 90% of the off-peak Energy hours at the Merom Hub and approximately 60% of the total Energy hours at the Merom Hub priced below our production cost at our Merom facility. Our goal is for Hallador Power to generate approximately 1.5 million MWh on a quarterly basis, which equates to approximately 6.0 million MWh annually (see Hallador Power’s capacity and utilization information below).  During the first half of 2024, Hallador Power generated 1,596,000 MWh, or 53% of our target. During the first half 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 June 30, Six Months Ended June 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) 911 917 874 917 Accredited capacity utilization (iii) 39 % 52 % 42 % 58 % (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 860 MW per day for 2024 and 2023, respectively. Accreditations are 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. 16 Table of Contents 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 future Capacity, which we believe makes our forward Capacity sales goals attainable as illustrated in our "Solid Forward Sales Position" table below. Our forward contracted energy sales position has a significant price increase in future years as illustrated in the graph below. Lower Energy prices negatively affected both HPC’s generation model and the dispatch rates of Sunrise Coal’s utility customers. In response to dispatching less, those customers slowed coal shipments from Sunrise during the winter season and throughout the shoulder season this spring. 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 130 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. Historically, Sunrise Coal has generated approximately six million tons of coal annually. Following the restructuring, we expect Sunrise to produce roughly 3.5 million tons of coal on an annualized basis for 2024. Total production for the first half of 2024 was 2.2 million tons, and we shipped 2.1 tons at an average sales price of $54.92 on a segment basis. If market conditions warrant, our current operations are capable of producing at a 4.5-million-ton annualized pace. In 2024, we have also secured supplemental coal from third party suppliers at favorable prices. This allows us to diversify self-production supply risk and provides us with additional flexibility in our sales portfolio. The optionality to obtain low-cost tons either internally or from third parties while capturing upward swings in the commodities markets for coal should further maximize margins while optimizing fuel costs at our Merom facility. In response to lower Energy prices and our challenging mining conditions during the first half of 2024, we executed on several financing opportunities, including raising $34.5 million through an At-The-Market (“ATM”) equity offering selling 4.7 million shares at an average price of $7.38 per share and borrowing $5.0 million from several Directors on our Board. In June, we received a $45.0 million prepayment for an 11-month forward Energy sale representing approximately 22% of our annual 6.0 million MWh goal during the term of the contract. 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. 17 Table of Contents OVERVIEW I. Q2 2024 Net Loss of $10.2 million. a. Electric Operations: During the second quarter of 2024, we sold 780,000 MWh representing a 4.4% decline in total MWh sold and an increase of $0.90 in operating revenues per MWh from Q1 2024. The decline in total MWh sold during Q2 2024 was driven by MISO pricing that was lower than our cost to produce for approximately two-thirds of the quarter, lower Electric Power demand due to a mild 2024 spring and summer and higher Gas utilization due to low Gas pricing. i. In Q2 2024, Electric Operations operating revenues were $57.0 million, or $73.10 per MWh, on a segment basis. ii. In Q2 2024, Electric Operations operating expenses per MWh were $64.39, which represents an increase of $10.88 per MWh from Q1 2024. iii. Q2 2024 Electric Operations income from operations was $8.71 per MWh, a decline of $9.98 from Q1 2024. b. Coal Operations: During the second quarter of 2024, 0.8 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 $13.0 million. This is a decline of 0.4 million tons of coal shipped from Q1 2024, primarily due to decreased demand from a mild 2024 spring and summer and continued low Gas prices. i. In Q2 2024, Coal Operations operating revenues were $46.4 million, or $54.69 per ton, on a segment basis. ii. In Q2 2024, Hallador's Coal Operations operating expenses were $68.02 per ton on a segment basis, which represents a $3.50 per ton increase from Q1 2024. While Coal Operations operating expenses decreased $20.6 million in the second quarter of 2024 compared to the first quarter, tons sold also decreased 365,000 tons, or 30.1%, causing a higher operating expense per ton amount. iii. We recorded a loss from operations for the quarter of $(13.33) per ton on a segment basis. This is a decline of $(3.89) per ton from Q1 2024 income from operations. These declines were due primarily to the reduction in contract average sales prices and the reduction in demand for coal due to low Gas prices. II. Q2 2024 Activity a. Cash Flow & Debt i. During Q2 2024, our operating cash flow was $23.5 million, and we decreased our bank debt by $31.5 million. ii. As of June 30, 2024, our bank debt was $45.5 million, liquidity was $60.7 million, and our leverage ratio came in at 2.12X, within our covenant of 2.25X. iii. During Q2 2024, we entered into an 11-month, $45.0 million prepaid physically delivered power contract in which we will provide a total of 1,302,480 MW, as discussed in “Item 1. Footnote 7 – Revenue”. iv. During Q2 2024, we paid off the $5.0 million unsecured one-year notes from related parties affiliated with certain members of the Board of Directors that were issued during Q1 2024. v. Our ATM offering program raised $27.9 million through the issuance of 3.9 million shares of our common stock. vi. We converted our remaining $11.0 million of senior unsecured convertible notes, including accrued interest with 1,840,729 shares of our Company common stock. We also issued 249,271 shares of our Company’s common stock as additional value to the holders for converting. 18 Table of Contents III. Solid Forward Sales Position (unaudited) 2024 2025 2026 2027 2028 2029 Total Power Energy Contracted MWh (in millions) 1.75 2.48 1.83 1.78 1.09 0.27 9.20 Average contracted price per MWh $ 36.22 $ 35.70 $ 55.37 $ 54.65 $ 52.98 $ 51.00 Contracted revenue (in millions) $ 63.39 $ 88.54 $ 101.33 $ 97.28 $ 57.75 $ 13.77 $ 422.06 Capacity Average daily contracted capacity MWh 772 801 744 623 454 100 Average contracted capacity price per MWd $ 207 $ 198 $ 230 $ 226 $ 225 $ 230 Contracted capacity revenue (in millions) $ 29.40 $ 57.89 $ 62.46 $ 51.39 $ 37.39 $ 3.47 $ 242.00 Total Energy & Capacity Revenue Contracted Power revenue (in millions) $ 92.79 $ 146.43 $ 163.79 $ 148.67 $ 95.14 $ 17.24 $ 664.06 Coal Priced tons - 3rd party (in millions) 1.26 1.78 0.50 0.50 — — 4.04 Avg price per ton - 3rd party $ 50.08 $ 50.04 $ 55.50 $ 55.50 $ — $ — Contracted coal revenue - 3rd party (in millions) $ 63.10 $ 89.07 $ 27.75 $ 27.75 $ — $ — $ 207.67 Committed and unpriced tons - 3rd party (in millions) — 1 1 1 — — 3 Total contracted tons - 3rd party (in millions) 1.26 2.78 1.50 1.50 — — 7.04 TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED $ 155.89 $ 235.50 $ 191.54 $ 176.42 $ 95.14 $ 17.24 $ 871.73 Priced tons - Merom (in millions) 0.60 2.30 2.30 2.30 2.30 — 9.80 Avg price per ton - Merom $ 51.00 $ 51.00 $ 51.00 $ 51.00 $ 51.00 $ — Contracted coal revenue - Merom (in millions) $ 30.60 $ 117.30 $ 117.30 $ 117.30 $ 117.30 $ — $ 499.80 TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT $ 186.49 $ 352.80 $ 308.84 $ 293.72 $ 212.44 $ 17.24 $ 1,371.53 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 $39.9 million and $44.2 million for the six months ended June 30, 2024 and 2023, respectively. b. Our projected electric capital expenditure budget for the remainder of 2024 is $6.5 million. Our projected coal operations capital expenditure budget for the remainder of 2024 is $8.8 million. c. We paid down bank debt of $46.0 million in the first half of 2024. As of June 30, 2024, our bank debt was $45.5 million. d. We expect cash from operations generated primarily to fund our capital expenditures and our debt service. As of June 30, 2024, we also had an additional borrowing capacity of $54.4 million. 19 Table of Contents 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 $16.9 million, including $5.5 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 first six months of 2024, capex was $28.0 million allocated as follows (in millions): Oaktown – maintenance capex $ 14.1 Oaktown – investment 2.1 Freelandville Mine — Merom Plant 11.5 Other 0.3 Capex per the Condensed Consolidated Statements of Cash Flows $ 28.0 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 wholly-owned subsidiary Summit Terminal LLC, a logistics transport facility located on the Ohio River. Electric Operations Three Months Ended June 30, Six Months Ended June 30, 2024 2023 2024 2023 (in thousands) (in thousands) Delivered Energy $ 39,973 $ 53,862 $ 86,955 $ 130,284 Capacity 16,873 17,155 28,646 33,125 Other 174 86 331 188 OPERATING REVENUES: 57,020 71,103 115,932 163,597 EXPENSES: Fuel 22,485 42,972 46,920 96,380 Other operating and maintenance costs 14,183 5,439 19,782 10,913 Utilities 143 116 225 219 Labor 7,160 7,469 14,843 16,166 Depreciation, depletion and amortization 4,698 4,675 9,395 9,350 Asset retirement obligations accretion 113 156 224 309 General and administrative 1,450 1,020 2,508 2,299 Total operating expenses 50,232 61,847 93,897 135,636 INCOME FROM OPERATIONS $ 6,788 $ 9,256 $ 22,035 $ 27,961 20 Table of Contents Three Months Ended June 30, Six Months Ended June 30, 2024 2023 2024 2023 (per MWh) (per MWh) MWh Sold 780 1,043 1,596 2,305 Delivered Energy $ 51.25 $ 51.64 $ 54.48 $ 56.52 Capacity 21.63 16.41 17.95 14.37 Other 0.22 0.08 0.21 0.08 OPERATING REVENUES: 73.10 68.13 72.64 70.97 EXPENSES: Fuel 28.83 41.20 29.40 41.81 Other operating and maintenance costs 18.18 5.21 12.39 4.73 Utilities 0.18 0.11 0.14 0.10 Labor 9.18 7.16 9.30 7.01 Depreciation, depletion and amortization 6.02 4.48 5.89 4.06 Asset retirement obligations accretion 0.14 0.15 0.14 0.13 General and administrative 1.86 0.98 1.57 1.00 Total operating expenses 64.39 59.29 58.83 58.84 INCOME FROM OPERATIONS: $ 8.71 $ 8.84 $ 13.81 $ 12.13 2024 vs. 2023 (second quarter) Operating revenues from electric operations decreased $14.1 million, or 19.8%, compared to the second quarter of 2023 due to approximately 60% of total Energy hours at the Merom Hub being priced below our production cost at our Merom Facility, low Electric Power demand due to a mild 2024 spring and summer, and higher demand for Gas as Gas prices averaged $2.08 per MBtu during the second quarter of 2024 compared to $2.16 per MBtu during the second quarter of 2023. Fuel decreased $20.5 million, or 47.7%, compared to the second quarter of 2023 due to lower coal usage and energy production as a result of weakened demand for electricity. Electric production decreased by 263,000 MWh, or 25.2%, from the second quarter of 2023. We were also able to acquire third-party coal at prices below our production costs for coal, further reducing our fuel expense during the quarter. Other operating and maintenance costs increased $8.7 million, or 160.8%, compared to the second quarter of 2023 primarily due to the planned maintenance outage which resulted in $6.8 million in additional costs for the period. Income from operations decreased $2.5 million, or 26.7%, and decreased $0.13 per MWh, from the three months ended June 30, 2023. The main drivers of this change in income from operations are described in the discussion above. 2024 vs. 2023 (first six months) Operating revenues from electric operations decreased $47.7 million, or 29.1%, compared to the first half of 2023 due to MISO pricing that was lower than our cost to produce at times during the period, low Power demand due to a mild 2024 spring and summer, and higher demand for Gas as Gas prices during the spring season of 2024 (March through May) averaged $1.74 per MBtu compared to $2.21 per MBtu in the spring season of 2023. Fuel decreased $49.5 million, or 51.3%, compared to the first half of 2023 due to lower coal usage and production as a result of weakened demand. Production decreased by 709,000 MWh, or 30.8%, from the first six months of 2023. Gas average spot prices were down $0.30 per MMBtu decreasing the demand for Electric Power. Other operating and maintenance costs increased $8.9 million, or 81.3%, compared to the first half of 2023 primarily due to the planned maintenance outage which resulted in $6.6 million in additional costs for the period. Income from operations decreased $5.9 million, or 21.2%, and increased $1.68 per MWh, from the six months ended June 30, 2023. The main drivers of this change in income from operations are described in the discussion above. 21 Table of Contents Coal Operations Three Months Ended June 30, Six Months Ended June 30, 2024 2023 2024 2023 (in thousands) (in thousands) OPERATING REVENUES: $ 46,429 $ 113,098 $ 113,299 $ 208,371 EXPENSES: Fuel 750 1,610 1,985 4,175 Other operating and maintenance costs 21,597 36,275 53,388 63,182 Utilities 3,253 4,226 7,545 8,620 Labor 19,395 29,059 46,880 60,893 Depreciation, depletion and amortization 8,930 12,466 19,658 25,741 Asset retirement obligations accretion 286 305 574 603 Exploration costs 47 305 117 511 General and administrative 3,492 2,489 5,930 5,195 Total operating expenses 57,750 86,735 136,077 168,920 INCOME (LOSS) FROM OPERATIONS $ (11,321 ) $ 26,363 $ (22,778 ) $ 39,451 Three Months Ended June 30, Six Months Ended June 30, 2024 2023 2024 2023 (per ton) (per ton) Tons Sold 849 1,714 2,063 3,407 OPERATING REVENUES: $ 54.69 $ 65.98 $ 54.92 $ 61.16 EXPENSES: Fuel 0.88 0.94 0.96 1.23 Other operating and maintenance costs 25.44 21.16 25.88 18.54 Utilities 3.83 2.47 3.66 2.53 Labor 22.84 16.95 22.72 17.87 Depreciation, depletion and amortization 10.52 7.27 9.53 7.56 Asset retirement obligations accretion 0.34 0.18 0.28 0.18 Exploration costs 0.06 0.18 0.06 0.15 General and administrative 4.11 1.45 2.87 1.52 Total operating expenses 68.02 50.60 65.96 49.58 INCOME (LOSS) FROM OPERATIONS: $ (13.33 ) $ 15.38 $ (11.04 ) $ 11.58 2024 vs. 2023 (second quarter) Segment operating revenues from coal operations decreased $66.7 million, or 58.9%, from the second quarter of 2023. Consolidated operating revenues from coal operations decreased $56.0 million, or 63%, from the second 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 $11.29 per ton and we sold 0.9 million tons less compared to the second quarter of 2023. Our average sales price on a consolidated basis decreased $7.21 per ton and we sold 0.8 million tons less compared to the second quarter of 2023. Operating revenues for the second quarter of 2024 include $12.9 million in sales to the Merom plant which were eliminated in the consolidation. Other operating and maintenance costs decreased $14.7 million, or 40.5%, and labor decreased $9.7 million, or 33.3%, from the second quarter of 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 second quarter 2024, we produced 0.4 million tons less than first quarter 2024, we reduced production days from 7 days to 5 days and further reduced our coal employee headcount by 130 employees. Depreciation, depletion, and amortization decreased $3.5 million, or 28.4%, from the second quarter of 2023 due to decreases in coal production and the remaining useful lives of the mine development assets. Income (loss) from operations decreased $37.7 million, or 142.9%, and decreased $28.71 per ton, from the three months ended June 30, 2023. The main drivers of this change in income (loss) from operations are described in the discussion above. 22 Table of Contents 2024 vs. 2023 (first six months) Segment operating revenues from coal operations decreased $95.1 million, or 45.6%, from the first half of 2023. Consolidated operating revenues from coal operations decreased $100.8 million, or 55%, from the first half 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 $6.24 per ton and we sold 1.3 million tons less compared to the first six months of 2023. Our average sales price, on a consolidated basis, for the six months ended 2024, decreased $3.11 per ton and we sold 1.6 million tons less compared to the first six months of 2023. Other operating and maintenance costs decreased $9.8 million, or 15.5%, and labor decreased $14.0 million, or 23.0%, from the first six months of 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 six months of 2024, we produced 1.6 million tons less on a segment basis than first six months of 2023, we went from 5 mines producing to 2 mines producing and further reduced our coal employee headcount by 339 employees. Depreciation, depletion, and amortization decreased $6.1 million, or 23.6%, from the first half of 2023 due to decreases in coal production and the remaining useful lives of the mine development assets. Income (loss) from operations decreased $62.2 million, or 157.7%, and decreased $22.62 per ton, from the six months ended June 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 3rd 2023 4th 2023 1st 2024 2nd 2024 T4Qs Tons produced 1,594 1,331 1,271 889 5,085 Tons sold 2,054 1,461 1,214 849 5,578 Wash plant recovery in % 65 % 62 % 60 % 59 % Capex $ 11,570 $ 17,867 $ 8,632 $ 7,560 $ 45,629 Maintenance capex $ 7,938 $ 13,567 $ 8,085 $ 6,014 $ 35,604 Maintenance capex per ton $ 3.86 $ 9.29 $ 6.66 $ 7.08 $ 6.38 All Mines 3rd 2022 4th 2022 1st 2023 2nd 2023 T4Qs Tons produced 1,663 1,721 2,006 1,723 7,113 Tons sold 1,705 1,664 1,693 1,714 6,776 Wash plant recovery in % 69 % 68 % 70 % 67 % Capex $ 15,096 $ 12,368 $ 12,639 $ 14,445 $ 54,548 Maintenance capex $ 6,625 $ 5,748 $ 7,778 $ 9,754 $ 29,905 Maintenance capex per ton $ 3.89 $ 3.45 $ 4.59 $ 5.69 $ 4.41 Presentation of Consolidated Information EARNINGS (LOSS) PER SHARE 3rd 2023 4th 2023 1st 2024 2nd 2024 Basic $ 0.49 $ (0.31 ) $ (0.05 ) $ (0.27 ) Diluted $ 0.44 $ (0.31 ) $ (0.05 ) $ (0.27 ) 3rd 2022 4th 2022 1st 2023 2nd 2023 Basic $ 0.05 $ 0.91 $ 0.67 $ 0.51 Diluted $ 0.05 $ 0.83 $ 0.61 $ 0.47 INCOME TAXES Our effective tax rate (ETR) is estimated at ~23% and ~11% for the six months ended June 30, 2024, and 2023, respectively. For the six months ended June 30, 2024, we recorded income taxes using an estimated annual effective tax rate based upon projected annual income, 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. 23 Table of Contents 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. 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 June 30, 2024, and December 31, 2023, coal inventory includes NRV adjustments of $0.9 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. Management evaluates assets for impairment through an established process in which changes to significant assumptions such as prices, volumes and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future volumes, commodity prices, operating costs and capital investment plans, considering all available information at the date of review. Changes to any of the market-based assumptions can significantly affect estimates of undiscounted and discounted pre-tax cash flows and impact the recognition and amount of impairments. 24 Table of Contents ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK No material changes from the disclosure in our 2023 Annual Report on Form 10-K .