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. Our condensed consolidated financial statements should be read in conjunction with this discussion. The following 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. Throughout the first quarter, we continued our progress on transitioning the focus of Hallador from a coal production company to an integrated independent power producer (“IPP”). During the first three months of 2024, our Electric Operation's revenue exceeded that of our Coal Operation's revenue. Additionally, we were successful in adding approximately $138.0 million in forward energy and capacity sales, growing our Electric Operation’s forward sales book to approximately $657.0 million as of March 31, 2024. This represents 44% of Hallador’s $1.5 billion in total forward energy, capacity, and coal sales through 2029 (on a segment basis). However, we truly believe future sales from our Electric Operations will soon eclipse our sales revenues from our Coal Operations. Since January, we have evaluated and continue to evaluate several major power and capacity sales opportunities, including one proposal that if contracted would result in more than a billion dollars’ worth of potential forward power sales. We continue to see strong indicators that demand, and pricing remain on an upward trend, and this direction is paramount to our ongoing evaluations of these sales opportunities. Monitoring the equity markets strengthens our belief that investors in other IPPs are also anticipating similar increases in power demand, demonstrated most clearly through the more than doubling of market capitalizations of several of those IPPs across the previous twelve months. In support of our expectation that Hallador Power sales will continue to exceed our traditional Sunrise Coal subsidiary, we anticipate changing Hallador's SIC code to 4911 (electric services) from 1220 (bituminous coal producer) in the future. While we have seen continued weakness in spot power prices thus far in 2024, indicators for future power pricing appear much healthier. We believe these indicators are supported by both our forward power book pricing and the most recent future power curves. Additionally, natural gas future’s prices are in contango, meaning future gas prices exceed spot gas prices that have been depressing overall power prices for the last several quarters. As we discussed last quarter, the dynamics of the natural gas market paired with the non-standard mild weather throughout the Midwest impacted pricing and our power plant dispatch rates. Future prices seem to indicate easing on both these fronts which we view as a positive for our go-forward operations. This quarter, we also launched a targeted request for proposal for power demand supporting new development at our Merom Power Plant. Reponses are due in mid-May, but early indications point to a high level of interest. The RFP is available on our website for any interested parties that did not already receive the information. Our goal is for Hallador Power to generate approximately 1.5 million MWh on a quarterly basis, which equates to approximately 6 million MWh annually. During the first quarter, Hallador Power generated 816,000 MWh, or 54% of our target, despite an average price of $41.90. The favorable pricing is a result of experiencing sales prices as high as $250 per MWh for limited times during the quarter, balanced against several days of pricing below our variable cost to produce. These fluctuations led to an inconsistent dispatch schedule, which we expect to level out as we anticipate demand and pricing increases with seasonal weather changes and reduced gas stores. During the first quarter, Hallador Power generated 816,000 MWh at the following cost structure (on a segment basis): In Millions Per MWh Revenue: Capacity $ 11.80 $ 14.46 Delivered Energy and PPA 47.00 57.60 Total Electric Revenue $ 58.80 $ 72.06 Operating Expense: Fixed Cost $ 11.80 $ 14.46 Variable Cost 26.00 31.86 Total Electric Operating Expense $ 37.80 $ 46.32 Margin: $ 21.00 $ 25.74 16 Table of Contents When forward selling capacity, we target annual sales of around $65 million to offset our fixed annual costs at the plant of approximately $60 million. Our forward sales table demonstrates that we have already sold a large portion of our future capacity, which we believe makes our forward capacity sales goals attainable. As a condition of acquiring the Merom Power Plant, we agreed to sell 1.66 million MWh of energy in 2024 and 1.60 million MWh in 2025 at $34 per MWh to the plant seller, representing 27% of our annual 6 million MWh goal. Since this original transaction, we have been successful in selling over 5 million MWh of energy to third parties at an average price of approximately $52 per MWh over the years 2024-2029 as illustrated in the table below. During the first quarter, our variable costs were $31.88 per MWh. The low energy prices during the quarter necessitated that we run our plant at slower speeds resulting in more frequent than normal starts and stops to avoid selling below cost energy. Running in this manner is less fuel efficient than if we were able to consistently generate at a 6 million MWh pace, which could lower cost by as much as 10%. On February 23, 2024, our Coal Operations Segment undertook an initiative designed to strengthen our financial and operational efficiency and to create significant operational savings and higher margins in our coal segment. This step helps to advance our transition from a company primarily focused on coal production to a more resilient and diversified IPP. As part of this initiative, we idled production at our higher cost Prosperity Mine, and substantially idled production at the Freelandville Mine with minimal production until reclamation is finished on approximately May 31, 2024. This should reduce our capital reinvestment for coal production in 2024 by approximately $10 million. We also focused our seven units of underground equipment on four units of our lowest cost production at our Oaktown Mine. As part of the initiative, we reduced our workforce by approximately 110 employees. 17 Table of Contents Mining costs for the quarter were $53.38 per ton. However, at Oaktown, we saw mining costs in March decrease into the low $30s on a per ton basis. While there are several factors that impacted this cost reduction, we continue to monitor operations and strategic initiatives to better understand the longevity of these favorable conditions. 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. 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. We continued our build out of what we consider to be a best-in-class management team as we welcomed Marjorie Hargrave as our new CFO with broad-based experience in power production and capital markets. Adding Marjorie to our previous hires over the last two years, including expertise within the positions of our President of Hallador Power, our Chief Legal Officer (with Data communications expertise), our SVP of Power Marketing, and a Manager of Environmental Engineering, will accelerate our continued development of Hallador’s operational and future power acquisition capabilities. These prospects and our strong future sales have us very excited about the future of our company. 18 Table of Contents OVERVIEW I. Q1 2024 Net Loss of $1.7 million. a. 1.2 million tons of coal were shipped at an average sales price of $54.40 on a segment basis during the quarter, with approximately 0.3 million tons of that being shipped to the Merom Power Plant for $16.4 million. This is a decline of 0.2 million tons of coal from Q4 2023, primarily due to decreased demand from a mild winter and low natural gas prices. The average sales price of coal was $55.64 per ton on a consolidated basis. i. The sales price for remaining tons to ship for 2024 is expected to average $50.65 per ton on a consolidated basis (not including coal shipped to Merom). b. In Q1 2024, Hallador's coal operating costs were $53.38 per ton on a segment basis, which represents a $0.41 per ton decrease from Q4 2023. This decrease is a result of the reduction in production of our higher cost surface mines. c. We recorded coal margins for the quarter at $1.02 per ton on a segment basis. This is a decline of $7.97 per ton from Q4 2023 margins, due primarily to the reduction in contract average sales prices. II. Q1 2024 Activity a. Cash Flow & Debt i. During Q1 2024, our operating cash flow was $16.4 million, and we decreased our bank debt by $14.5 million. ii. As of March 31, 2024, our bank debt was $77.0 million, liquidity was $39.5 million, and our leverage ratio came in at 1.58X, within our covenant of 2.25X. iii. During Q1 2024, we issued unsecured one-year notes from related parties affiliated with certain members of the Board of Directors in the amount of $5.0 million. iv. An ATM raised $6.6 million through the issuance of 0.7 million shares of our common stock. v. We converted $8.0 million of senior unsecured convertible notes, including interest through August 2025 with 1,459,293 shares of our Company common stock. We converted $0.8 million of accrued interest with 122,605 shares of our Company's common stock. b. Power & Coal i. Power production was 0.8 million MWh for the quarter, an increase of 0.2 million from Q4 2023. ii. We initiated a Reorganization Plan in our Coal Operations designed to increase margins and adjust to current market conditions. Our production was 1.3 million tons for the quarter, 0.1 million less than Q4 2023. Approximately 0.3 million tons of that production were shipped to the Merom Power Plant in Q1 2024. 19 Table of Contents III. Solid Forward Sales Position - Segment Basis, Before Intercompany Eliminations 2024 2025 2026 2027 2028 2029 Total Power Energy Contracted MWh (in millions) 1.60 1.90 1.83 1.78 1.09 0.27 8.47 Contracted price per MWh $ 37.02 $ 36.06 $ 55.37 $ 54.65 $ 52.98 $ 51.00 Contracted revenue (in millions) $ 59.23 $ 68.51 $ 101.33 $ 97.28 $ 57.75 $ 13.77 $ 397.87 % Energy Sold* 27 % 32 % 31 % 30 % 18 % 5 % Capacity Average monthly contracted capacity 818 801 744 623 454 100 % Capacity Contracted** 106 % 82 % 77 % 64 % 47 % 10 % Average contracted capacity price per MWd $ 209 $ 198 $ 230 $ 226 $ 225 $ 230 Contracted capacity revenue (in millions) $ 47.01 $ 57.89 $ 62.46 $ 51.39 $ 37.39 $ 3.47 $ 259.61 Total Energy & Capacity Revenue Contracted Power Revenue (in millions) $ 106.24 $ 126.40 $ 163.79 $ 148.67 $ 95.14 $ 17.24 $ 657.48 Contracted Power Revenue per MWh* $ 44.39 $ 47.76 $ 68.96 $ 68.00 $ 66.31 $ 56.62 2024 average cost per MWh was $31.88 for the three months ended March 31, 2024 ($30.41 assuming intercompany sales of coal were sold at cost) 2024 Power Capex Budget (in millions) excluding ELG requirements $ 18.00 Coal Priced tons - 3rd party (in millions) 2.48 1.78 0.50 0.50 — — 5.26 Average price per ton - 3rd party $ 50.65 $ 50.04 $ 55.50 $ 55.50 $ — $ — Priced tons (in millions) - Hallador Power 1.20 2.30 2.30 2.30 2.30 — 10.40 Average price per ton - Hallador Power $ 51.00 $ 51.00 $ 51.00 $ 51.00 $ 51.00 $ — Contracted coal revenue (in millions) $ 186.81 $ 206.37 $ 145.05 $ 145.05 $ 117.30 $ — $ 800.58 % Priced 82 % 91 % 62 % 62 % 51 % 0 % Committed & unpriced tons (in millions) - 3rd party — 1.00 1.00 1.00 — — 3.00 Committed & unpriced tons (in millions) - Hallador Power — — — — — — — Total contracted tons (in millions) 3.68 5.08 3.80 3.80 2.30 — 18.66 % Coal Sold* 82 % 113 % 84 % 84 % 51 % 0 % Average cost per ton of coal was $53.38 for the three months ended March 31, 2024 2024 Coal Capex Budget (in millions) $ 25.00 TOTAL CONTRACTED REVENUE (IN MILLIONS) $ 293.05 $ 332.77 $ 308.84 $ 293.72 $ 212.44 $ 17.24 $ 1,458.06 *Based on coal production capacity of 4.5 million tons and 6.0 million MWh annually. **Based on a MISO accreditation of 769 MW per day through 2024, up to 971 MW per day for 2025. Accreditations are adjusted annually based on 3-year rolling performance metrics. 20 Table of Contents 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 $16.4 million and $26.1 million for the three months ended March 31, 2024 and 2023, respectively. i. Operating margins for electric, which we define as operating revenues less operating expenses on a segment basis, were $21.1 million. Operating margins were $22.1 million on a consolidated basis. ii. Operating margins from coal sales, which we define as coal sales less operating expenses, were $1.2 million on a segment basis, during the first three months of 2024, down from $28.9 million during the first three months of 2023. Tons shipped in the first three months of 2024 to the Merom Power Plant were sold at break-even, however due to timing of the usage of the coal in the Plant, we had negative operating margins of $1.2 million which were eliminated in consolidation. 1. Our operating margins from coal sales were $1.02 per ton on a segment basis in the first three months of 2024 compared to $17.07 in the first three months of 2023. 2. We shipped 1.2 million tons of coal in the first three months of 2024, with 0.3 million tons of that being shipped to the Merom Power Plant. b. Our projected electric capital expenditure budget for the remainder of 2024 is $11.8 million. Our projected coal operations capital expenditure budget for the remainder of 2024 is $16.3 million, of which approximately one-half is anticipated for maintenance capex. c. We paid down bank debt of $14.5 million in the first three months of 2024. As of March 31, 2024, our bank debt was $77.0 million. d. In March of 2024, we issued unsecured promissory notes, having a 12-month maturity date and 12% per annum interest rate to related parties affiliated with certain members of our Board of Directors. The primary purpose of this issuance was to support liquidity and accelerate strategic initiatives. e. We expect cash from operations generated primarily to fund our capital expenditures and our debt service. As of March 31, 2024, we also had an additional borrowing capacity of $37.9 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 $16.4 million, including $5.4 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 $37.5 million to cover ARO. CAPITAL EXPENDITURES (capex) For the first three months of 2024, capex was $14.9 million allocated as follows (in millions): Oaktown – maintenance capex $ 5.7 Oaktown – investment 3.0 Freelandville Mine — Merom Plant 6.2 Other — Capex per the Condensed Consolidated Statements of Cash Flows $ 14.9 21 Table of Contents 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 March 31, 2024 2023 (in thousands) OPERATING REVENUES: $ 58,912 $ 92,494 EXPENSES: Operating expenses 37,799 67,682 Depreciation, depletion and amortization 4,697 4,675 Asset retirement obligations accretion 111 153 General and administrative 1,058 1,279 Total operating expenses 43,665 73,789 INCOME FROM OPERATIONS $ 15,247 $ 18,705 Operating revenues from electric operations decreased $33.6 million, or 36%, compared to the first quarter of 2023 due to reduced production of power as a result of a mild winter and decreased natural gas prices. Operating expenses decreased $29.9 million, or 44%, compared to the first quarter of 2023 due to a decrease in production as well as costs related to the coal purchase agreement signed with Hoosier related to the Merom Acquisition in 2022. The coal purchase agreement included fixed prices which were below market prices at the date we entered into the agreement. As a result of the below-market contract, there were $17.8 million in additional operating expenses for coal purchased as a result of amortizing the contract asset during the first quarter of 2023. Quarterly electric sales and cost data (in thousands, except per MWh data) are provided below. Fixed costs in the table are considered "non-GAAP" and are a component of operating expenses, the most comparable GAAP measure. We consider fixed costs to be costs associated with the plant whether or not the plant is in operation. 1st 2024 1st 2023 MWh sold 816 1,262 Capacity revenue $ 11,773 $ 15,970 Delivered energy and PPA revenue 46,982 76,422 Total electric sales 58,755 92,392 Less amortization of contract liability (12,788 ) (33,347 ) Total electric sales less amortization of contract liability $ 45,967 $ 59,045 Average price/MWh of delivered energy and PPA revenue less amortization of contract liability $ 41.90 $ 34.13 Operating expenses (on a segment basis) $ 37,799 $ 67,682 Less fixed costs (11,782 ) (12,807 ) Less amortization of contract asset — (17,778 ) Operating expenses less fixed costs and amortization of contract asset $ 26,017 $ 37,097 Average variable cost/MWh of operating expenses less fixed costs and amortization of contract asset $ 31.88 $ 29.40 Energy and PPA margin less fixed costs and amortization of contract asset and liabilities $ 8,177 $ 5,978 Energy and PPA margin/MWh less fixed costs amortization of contract asset and liabilities $ 10.02 $ 4.74 22 Table of Contents Coal Operations Three Months Ended March 31, 2024 2023 (in thousands) OPERATING REVENUES: $ 66,870 $ 95,273 EXPENSES: Operating expenses 64,803 65,700 Depreciation, depletion and amortization 10,728 13,275 Asset retirement obligations accretion 288 298 Exploration costs 70 206 General and administrative 2,438 2,706 Total operating expenses 78,327 82,185 (LOSS) INCOME FROM OPERATIONS $ (11,457 ) $ 13,088 Operating revenues from coal operations decreased $28.4 million, or 30%, from the first quarter of 2023 due to reductions in volume and average sales price for our coal. Our average sales price decreased $1.48 per ton and we sold 0.5 million tons less compared to the first quarter of 2023. Operating revenues for the first quarter of 2024 include $16.4 million in sales to the Merom plant which were eliminated in the consolidation. Operating expenses increased by $14.57 per ton sold over the first quarter of 2023. This increase was due to one-time termination benefits of $1.1 million related to the Reorganization Plan disclosed in “Note 16 — Organizational Restructuring” to the Condensed Consolidated Financial Statements, the addition of the higher-cost Prosperity surface mine, poor temporary mining conditions at Oaktown, and continued significant inflationary pressures that have continued to elevate the costs. Depreciation, depletion, and amortization decreased $2.5 million, or 19%, from the first quarter of 2023 due to decreases in coal production and the remaining useful lives of the mine development assets. 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 2nd 2023 3rd 2023 4th 2023 1st 2024 T4Qs Tons produced 1,723 1,594 1,331 1,271 5,919 Tons sold 1,714 2,054 1,461 1,214 6,443 Coal sales $ 112,171 $ 134,400 $ 91,714 $ 66,036 $ 404,321 Average price per ton $ 65.44 $ 65.43 $ 62.77 $ 54.40 $ 62.75 Wash plant recovery in % 67 % 65 % 62 % 60 % Operating costs $ 71,168 $ 95,592 $ 78,581 $ 64,803 $ 310,144 Average cost per ton $ 41.52 $ 46.54 $ 53.79 $ 53.38 $ 48.14 Margin $ 41,003 $ 38,808 $ 13,133 $ 1,233 $ 94,177 Margin per ton $ 23.92 $ 18.89 $ 8.99 $ 1.02 $ 14.62 Capex $ 14,445 $ 11,570 $ 17,867 $ 8,632 $ 52,514 Maintenance capex $ 9,754 $ 7,938 $ 13,567 $ 8,085 $ 39,344 Maintenance capex per ton $ 5.69 $ 3.86 $ 9.29 $ 6.66 $ 6.11 23 Table of Contents All Mines 2nd 2022 3rd 2022 4th 2022 1st 2023 T4Qs Tons produced 1,762 1,663 1,721 2,006 7,152 Tons sold 1,595 1,705 1,664 1,693 6,657 Coal sales $ 64,161 $ 83,563 $ 84,641 $ 94,602 $ 326,967 Average price per ton $ 40.23 $ 49.01 $ 50.87 $ 55.88 $ 49.12 Wash plant recovery in % 71 % 69 % 68 % 70 % Operating costs $ 50,776 $ 63,876 $ 67,319 $ 65,700 $ 247,671 Average cost per ton $ 31.83 $ 37.46 $ 40.46 $ 38.81 $ 37.20 Margin $ 13,385 $ 19,687 $ 17,322 $ 28,902 $ 79,296 Margin per ton $ 8.39 $ 11.55 $ 10.41 $ 17.07 $ 11.91 Capex $ 13,821 $ 15,096 $ 12,368 $ 12,639 $ 53,924 Maintenance capex $ 7,600 $ 6,625 $ 5,748 $ 7,778 $ 27,751 Maintenance capex per ton $ 4.76 $ 3.89 $ 3.45 $ 4.59 $ 4.17 Presentation of Consolidated Information EARNINGS (LOSS) PER SHARE 2nd 2023 3rd 2023 4th 2023 1st 2024 Basic $ 0.51 $ 0.49 $ (0.31 ) $ (0.05 ) Diluted $ 0.47 $ 0.44 $ (0.31 ) $ (0.05 ) 2nd 2022 3rd 2022 4th 2022 1st 2023 Basic $ (0.11 ) $ 0.05 $ 0.91 $ 0.67 Diluted $ (0.11 ) $ 0.05 $ 0.83 $ 0.61 INCOME TAXES Our effective tax rate (ETR) is estimated at ~26% and ~13% for the three months ended March 31, 2024, and 2023, respectively. For the three months ended March 31, 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. 24 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. There were no significant changes to our NRV adjustment estimates from the prior year. 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. 25 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 .