HALLADOR ENERGY CO 10-K

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The following discussion and analysis, which should be read in conjunction with our consolidated financial statements, is intended to assist in providing an understanding of our results of operations and financial condition and is organized as follows: ● Overview. This section provides a general description of our business and recent events. ● Results of Operations. This section provides an analysis of our results of operations for the years ended December 31, 2025 and 2024. ● Liquidity and Capital Resources. This section provides an analysis of our liquidity and consolidated statements of cash flows. ● Critical Accounting Policies, Judgments and Estimates. This section discusses those material accounting policies that involve uncertainties and require significant judgment in their application. ● Quantitative and Qualitative Disclosures about Market Risk. This section provides discussion and analysis of the commodity, interest rate and other market risks that our company faces. Included below is an analysis of our results of operations and cash flows for 2025, as compared to 2024. An analysis of our results of operations and cash flows for 2024, as compared to 2023, can be found under “ Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in Part II of our Annual Report on Form 10-K for the year ended December 31, 2024, which is available through the SEC’s website at www.sec.gov. The capitalized terms used below have been defined in the notes to our consolidated financial statements. In the following text, the terms “we,” “our,” “our company” and “us” may refer, as the context requires, to Hallador or collectively to Hallador and its subsidiaries. OVERVIEW General Hallador is a vertically integrated, independent power producer IPP and fuel company with operations primarily in Indiana. The Company operates across multiple stages of the energy supply chain, from accredited capacity and energy to coal. The Company’s electric operations are located within the MISO footprint. Our operations comprise Hallador Power that provides accredited capacity and energy to utilities and other energy market participants through the MISO interconnection, and Sunrise that mines bituminous coal in Indiana to serve various power plants in the Midwest and Southeast United States. Operations Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The Company also holds 50% interests in Sunrise Energy, LLC and Oaktown Gas, LLC, which are accounted for using the equity method. Through its operating subsidiaries, the Company delivers three main products to its customers. Accredited Capacity. Hallador Power, the Company’s wholly-owned electric subsidiary, owns and operates the Merom Power Plant (“Merom”), a 1,080 MW coal-fired power generating station, consisting of two steam turbine generators. Unit 1 entered commercial operations in 1982 and Unit 2 in 1983. The units are dispatched through its MISO interconnection. In order to purchase energy through the MISO Interconnection, an end user must supply or purchase accredited capacity for an equivalent load. As accredited capacity is primarily available in large quantities from dispatchable sources of energy, such as natural gas and coal-fired power plants, Hallador Power sells accredited capacity to utilities and other energy market participants within the MISO system through PPAs and other bilateral transactions. 44 Table of Contents Energy. In addition to accredited capacity, Hallador Power sells wholesale energy to utilities, generation and transmission cooperatives, and other energy market participants within the MISO system through PPAs and other bilateral transactions, and sells on a spot basis in the day-ahead and real-time MISO markets. Coal. Sunrise, the Company’s wholly-owned mining subsidiary, mines coal from reserves found in the ILB. Coal mined by Sunrise is used as a primary fuel source for generating electricity at various power plants in the Midwest and Southeast United States. In addition, Sunrise has a developed infrastructure for the transport of coal, which is typically sold free on board from the shipping point, including rail networks and truck loading systems, facilitating the efficient movement of the resource from the mine to its customers. Sunrise’s Oaktown Mining Complex is about twenty miles from Merom, which is located in Sullivan County, Indiana, enabling Merom and Sunrise to take advantage of low-cost fuel on a delivered basis. In the first quarter of 2024, we announced a restructuring of our Coal Operations to address the increase in costs we experienced at our mines, that resulted in a significant reduction in headcount and the temporary idling of our mining operations at the Oaktown Mine No. 2. During the fourth quarter of 2024, we completed our review of the coal mining facilities and future mining plans. The analysis was based upon our finalized coal mining operating plans, market driven pricing and cost trends. As part of that analysis, we determined the carrying amount of our coal mining long-lived asset group was not recoverable and recorded a non-cash, long-lived asset impairment charge of $215.1 million in the fourth quarter of 2024. See “Note 19 – Impairment of Coal Properties” to the Consolidated Financial Statements in this Form 10-K for further information on the impairment analysis. Strategy and Management Focus We view our business as two integrated operations, “Electric Operations” (our gigawatt Merom power generating station), and “Coal Operations” (our coal mining and coal sales group). We strive to achieve margin expansion through organic revenue growth and profitability in our operations by negotiating and fulfilling contracts for accredited capacity, wholesale energy, and thermal coal to utilities and other energy market participants. We continue to monitor opportunities to expand the volume of our electric generation capabilities through expansion of existing facilities utilizing MISO’s ERAS program, or via acquisition. We continue to evaluate other strategic transactions that could add durability, scale, and geographic expansion opportunities to our Electric Operations. While these types of deals are limited and complex, we believe that Hallador is well-positioned to transform retiring and/or underperforming assets into future opportunities. This will enable us to supply high demand end users, such as data centers and on-shored industrial customers, with minimal impact to retail consumers. In addition, we focus our organic capital investments on strategic maintenance projects to maintain our safe operational performance and improve the reliability of Merom. As discussed further under “Liquidity and Capital Resources — Capitalization” below, we also seek to maintain our debt at levels that provide for attractive equity returns without assuming undue risk. Competition and Other External Factors We are experiencing competition in both our Electric and Coal Operations. This competition drives lower market prices for our products and services. Competitors for our Electric Operations include other power generators who bid into the MISO interconnection, while competitors for our Coal Operations include other mining entities that are able to service our existing and potential customers via truck or rail within the Midwest and Southeast United States. 45 Table of Contents RESULTS OF OPERATIONS Our contracted forward sales for electricity, accredited capacity and coal are detailed below with estimated revenue from forward sales of $1.3 billion as of December 31, 2025. Forward Sales Position ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2026 ​ ​ ​ 2027 ​ ​ ​ 2028 ​ ​ ​ 2029 ​ ​ ​ Total Power ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Energy ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Contracted MWh (in millions) ​ 4.06 ​ 3.06 ​ 1.09 ​ 0.27 ​ 8.48 Average contracted price per MWh ​ $ 43.32 ​ $ 46.50 ​ $ 52.94 ​ $ 51.33 ​ ​ ​ Contracted revenue (in millions) ​ $ 175.88 ​ $ 142.29 ​ $ 57.70 ​ $ 13.86 ​ $ 389.73 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Accredited Capacity ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average daily contracted accredited capacity MW ​ 733 ​ 623 ​ 454 ​ 100 ​ ​ Average contracted accredited capacity price per MWd ​ $ 230 ​ $ 226 ​ $ 225 ​ $ 230 ​ ​ ​ Contracted accredited capacity revenue (in millions) ​ $ 61.54 ​ $ 51.40 ​ $ 37.33 ​ $ 3.47 ​ $ 153.74 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total Energy & Accredited Capacity Revenue ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Contracted Power revenue (in millions) ​ $ 237.42 ​ $ 193.69 ​ $ 95.03 ​ $ 17.33 ​ $ 543.47 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Coal ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Priced tons - 3rd party (in millions) ​ 2.73 ​ 2.50 ​ 0.50 ​ — ​ 5.73 Avg price per ton - 3rd party ​ $ 55.72 ​ $ 56.74 ​ $ 59.00 ​ $ — ​ ​ ​ Contracted coal revenue - 3rd party (in millions) ​ $ 152.12 ​ $ 141.85 ​ $ 29.50 ​ $ — ​ $ 323.47 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED ​ $ 389.54 ​ $ 335.54 ​ $ 124.53 ​ $ 17.33 ​ $ 866.94 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Priced tons - Intercompany (in millions) ​ 2.30 ​ 2.30 ​ 3.17 ​ — ​ 7.77 Avg price per ton - Intercompany ​ $ 51.00 ​ $ 51.00 ​ $ 51.00 ​ $ — ​ ​ ​ Contracted coal revenue - Intercompany (in millions) ​ $ 117.30 ​ $ 117.30 ​ $ 161.67 ​ $ — ​ $ 396.27 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT ​ $ 506.84 ​ $ 452.84 ​ $ 286.20 ​ $ 17.33 ​ $ 1,263.21 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ * Actual revenue related to 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. Discussion and Analysis of our Reportable Segments Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The Chief Operating Decision Maker (“CODM”), who is the Company’s Chief Executive Officer, reviews and assesses operating performance measures related to our Electric Operations and our Coal Operations segments. In addition to these reportable segments, the Company has a “Corporate and Other and Eliminations” category, which is not significant enough, on a stand-alone basis, to be considered an operating segment. Corporate and Other and Eliminations primarily consist of unallocated corporate costs and activities, including our 50% interests in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana and Oaktown Gas, LLC, which we account for using the equity method. 46 Table of Contents Electric Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2025 ​ 2024 ​ ​ (in thousands) Delivered energy ​ $ 252,644 ​ $ 203,434 Accredited capacity revenue ​ ​ 58,093 ​ ​ 58,093 Electric sales ​ $ 310,737 ​ $ 261,527 ​ ​ ​ ​ ​ ​ ​ Fuel ​ $ (132,573) ​ $ (111,768) Other operating costs (1) ​ ​ (5) ​ ​ (19) Other operating and maintenance costs (2) ​ ​ (29,358) ​ ​ (28,622) Cost of purchased power ​ ​ (20,892) ​ ​ (10,888) Utilities ​ ​ (4,612) ​ ​ (2,070) Labor ​ ​ (32,672) ​ ​ (30,842) General and administrative ​ ​ (5,195) ​ ​ (5,311) Segment EBITDA ​ ​ 85,430 ​ ​ 72,007 Other operating revenue ​ ​ 3,534 ​ ​ 946 Depreciation, depletion and amortization ​ ​ (22,681) ​ ​ (19,290) ARO accretion ​ ​ (497) ​ ​ (457) Interest income ​ ​ 52 ​ ​ 36 Interest expense ​ ​ (9,097) ​ ​ (1,875) Income before Income Taxes ​ $ 56,741 ​ $ 51,367 1) Other operating costs primarily include costs for lime dust. 2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1). ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2025 ​ 2024 ​ ​ (per MWh) MWh generated (in thousands) ​ ​ 4,696 ​ ​ 3,830 MWh purchased (in thousands) ​ ​ 479 ​ ​ 354 MWh sold (in thousands) ​ ​ 5,175 ​ ​ 4,184 ​ ​ ​ ​ ​ ​ ​ Delivered energy ​ $ 48.82 ​ $ 48.62 Accredited capacity revenue ​ ​ 11.23 ​ ​ 13.88 Electric sales ​ $ 60.05 ​ $ 62.50 ​ ​ ​ ​ ​ ​ ​ Fuel ​ $ (25.62) ​ $ (26.71) Other operating costs (1) ​ ​ — ​ ​ — Other operating and maintenance costs (2) ​ ​ (5.67) ​ ​ (6.84) Cost of purchased power ​ ​ (4.04) ​ ​ (2.60) Utilities ​ ​ (0.89) ​ ​ (0.49) Labor ​ ​ (6.31) ​ ​ (7.37) General and administrative ​ ​ (1.00) ​ ​ (1.27) Segment EBITDA ​ ​ 16.52 ​ ​ 17.22 Other operating revenue ​ ​ 0.68 ​ ​ 0.23 Depreciation, depletion and amortization ​ ​ (4.38) ​ ​ (4.61) ARO accretion ​ ​ (0.10) ​ ​ (0.11) Interest income ​ ​ 0.01 ​ ​ 0.01 Interest expense ​ ​ (1.76) ​ ​ (0.45) Income (Loss) before Income Taxes ​ $ 10.97 ​ $ 12.29 1) Other operating costs primarily include costs for lime dust. 2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1). 47 Table of Contents Segment operating revenues from electric operations increased $49.2 million, or 18.8%, compared to 2024 attributable to an increase in sales of delivered energy while accredited capacity revenue was stable. Our electric operations generated an additional 0.9 million MWh and purchased an additional 0.1 million MWh for resale resulting in incremental energy sales of 1.0 million MWh, an increase of 23.7% compared to 2024. Seasonal weather in the first and third quarters of 2025 leading to incremental generation was offset by lower plant availability due to equipment issues at Merom in the fourth quarter impacting total MWh generated. The price per MWh was relatively flat year-over-year at $48.82 for 2025 compared to $48.62 for 2024. Accredited capacity revenue totaled $58.1 million for each of the years ended December 31, 2025 and 2024. Other operating revenue increased $2.6 million, or 273.6%, compared to 2024 attributable to the exclusivity payments received during the contractual negotiations for the future accredited capacity and energy generated at Merom. Fuel costs on a segment basis increased $20.8 million, or 18.6%, from 2024. Fuel costs on a consolidated basis increased $15.3 million or 33.0%, from 2024. This increase is due to electricity generation increasing by 0.9 million MWh, or 22.6%. We used an incremental 0.3 million tons in production on both a segment and consolidated basis compared to the prior year. We utilized approximately 0.1 million more tons produced at the Oaktown mining complex in 2025 compared to 2024. The increase in demand for electric power was related to seasonal weather in the first and third quarters of 2025, which resulted in 0.6 million and 0.5 million incremental MWh respectively, compared to the same periods in 2024. The weather contributed to higher demand for natural gas in Indiana causing an increase in the average spot prices of $0.84 per thousand cubic feet, or 24.1% compared to 2024. Total fuel costs benefited from a slight decrease in the cost of coal consumed from $54.30 per ton in 2024 to $53.98 per ton in 2025. We also made an adjustment to coal inventory during the third quarter of 2025 as part of the Company’s routine inventory reconciliation process resulting in an increase in fuel costs of $2.6 million. Cost of purchased power increased $10.0 million, or 91.9%, from 2024. W hen there is an outage at one of the generating units at Merom or energy hours at the Merom Hub are priced below our production cost, we have the option to make net hourly purchases of power in the MISO market to satisfy our obligations, which we record as cost of purchased power. Approximately 47.0% of the 2025 net hourly purchases occurred in the fourth quarter as a result of the equipment issues. Utilities increased $2.5 million, or 122.8%, in 2025 compared to 2024. The change was attributable to increased production at Merom, as well as incremental billing for auxiliary power. Labor increased $1.8 million, or 5.9%, in 2025 versus 2024. The increase in labor costs is attributable to year-over-year wage increases and the use of outsourced labor. Interest expense increased $7.2 million, or 385.2%. The increase in our interest expense relates to accretion on our prepaid delivered energy contracts that were entered into in October 2024, and various points in 2025. Income before income taxes increased $5.4 million, or 10.5%, compared to 2024 and is attributable to the items described in the discussion above. 48 Table of Contents Coal Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2025 ​ 2024 ​ ​ (in thousands) Coal sales ​ $ 221,008 ​ $ 202,525 ​ ​ ​ ​ ​ ​ ​ Fuel ​ $ (2,088) ​ $ (2,851) Other operating and maintenance costs ​ ​ (99,883) ​ ​ (89,283) Utilities ​ ​ (12,189) ​ ​ (13,844) Labor ​ ​ (78,006) ​ ​ (85,322) General and administrative ​ ​ (8,712) ​ ​ (9,877) Segment EBITDA ​ ​ 20,130 ​ ​ 1,348 Other operating revenue ​ ​ 5,373 ​ ​ 2,559 Depreciation, depletion and amortization ​ ​ (18,465) ​ ​ (46,245) Asset impairment ​ ​ — ​ ​ (215,136) ARO accretion ​ ​ (1,267) ​ ​ (1,171) Exploration costs ​ ​ (216) ​ ​ (260) Gain (loss) on disposal or abandonment of assets, net ​ ​ 2,489 ​ ​ (1,629) Interest income ​ ​ 235 ​ ​ 197 Interest expense ​ ​ (7,799) ​ ​ (11,033) Settlement of litigation ​ ​ — ​ ​ (2,750) Income (Loss) before Income Taxes ​ $ 480 ​ $ (274,120) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2025 ​ 2024 ​ ​ (per ton) Tons sold ​ ​ 4,311 ​ 3,864 ​ ​ ​ ​ ​ ​ ​ Coal sales ​ $ 51.27 ​ $ 52.41 ​ ​ ​ ​ ​ ​ ​ Fuel ​ $ (0.48) ​ $ (0.74) Other operating and maintenance costs ​ ​ (23.17) ​ ​ (23.11) Utilities ​ ​ (2.83) ​ ​ (3.58) Labor ​ ​ (18.09) ​ ​ (22.08) General and administrative ​ ​ (2.02) ​ ​ (2.56) Segment EBITDA ​ ​ 4.68 ​ ​ 0.34 Other operating revenue ​ ​ 1.25 ​ ​ 0.66 Depreciation, depletion and amortization ​ ​ (4.28) ​ ​ (11.97) Asset impairment ​ ​ — ​ ​ (55.68) ARO accretion ​ ​ (0.29) ​ ​ (0.30) Exploration costs ​ ​ (0.05) ​ ​ (0.07) Gain (loss) on disposal or abandonment of assets, net ​ ​ 0.58 ​ ​ (0.42) Interest income ​ ​ 0.05 ​ ​ 0.05 Interest expense ​ ​ (1.81) ​ ​ (2.86) Settlement of litigation ​ ​ — ​ ​ (0.71) Income (Loss) before Income Taxes ​ $ 0.13 ​ $ (70.96) ​ During 2024, we undertook an Organizational Restructuring of our Coal Operations. See “ Note 17 – Organizational Restructuring ” in the Consolidated Financial Statements for further information. The Organizational Restructuring provided better operating leverage for our Coal Operations as decreased labor costs were a significant driver of our improved performance. ​ 49 Table of Contents Segment operating revenue from coal operations increased $18.5 million, or 9.1%, versus 2024, despite only actively mining Oaktown Mine No. 1 during 2025. The increase was due to increases in volume offset by a reduction in the average sales price for our coal. We sold 4.3 million tons of coal in 2025, an increase of 0.4 million tons, or 11.6%, versus 2024. Our average sales price, on a segment basis, decreased $1.14 per ton from $52.41 per ton to $51.27 per ton. The incremental sales were made possible through increased demand for coal fired electricity due to seasonal weather specifically in the third quarter of 2025. On a consolidated basis, third-party sales increased $11.2 million, or 8.2%, versus 2024 attributable to 0.3 million incremental tons sold, offset by a 3.5% reduction in our average third-party price per ton. Other operating and maintenance costs increased $10.6 million, or 11.9%, which is attributable to the 0.4 million ton, or 11.6%, increase in total tons sold versus 2024. Labor decreased $7.3 million, or 8.6%, from 2024, resulting in a reduction in labor cost per ton sold of $3.99 attributable to more efficient operations following the idling of Oaktown Mine No. 2 during 2024. The change was driven by the Reorganization Plan disclosed in “Note 17 — Organizational Restructuring” to the Consolidated Financial Statements. As part of the Organizational Restructuring, we incurred aggregate expenses of $1.9 million in 2024 that were included in coal operations labor costs. These charges related to compensation, tax, professional, and insurance related expenses and are considered non-recurring charges paid during 2024. Through the organizational restructuring and regular attrition during the year, our coal employee headcount decreased by 305 employees. We recorded an asset impairment of $215.1 million during 2024. During the fourth quarter of 2024, we completed our annual business plan review. We evaluated core hole samples at several of our mines, reviewing the quality of the mine seam and density of the coal. The core hole samples at our Oaktown Mine No. 2 mine were of a lower quality and density than that of Oaktown Mine No. 1. As such, we decided to temporarily seal Oaktown Mine No. 2, and to focus coal production at Oaktown Mine No. 1, which has lower recovery costs. Due to that decision, we determined a triggering event had occurred and completed an impairment review to determine if the carrying value of our coal properties were impaired by comparing the net book value of our coal properties to estimated undiscounted future net cash flows. The result of the undiscounted cash flow test indicated the carrying amount of our coal properties may not be recoverable. As a result, the Company prepared a discounted cash flow model (Level 3 fair value measurement under the fair value hierarchy) to estimate fair value and recorded an impairment charge. Depreciation, Depletion and Amortization decreased by $27.8 million, or 60.1%, in 2025 compared to 2024. Following the impairment of our coal operations discussed above, the cost basis of our coal operations assets upon which depreciation, depletion and amortization is calculated was much lower resulting in significantly lower expense. Interest expense decreased $3.2 million, or 29.3%, from $11.0 million in 2024 to $7.8 million in 2025. The decrease is attributable to the net paydown of the Company’s bank facility from $44.0 million at December 31, 2024 to $30.0 million at December 31, 2025 coupled with decreased interest rates of 1.5% on our revolving credit facility and 0.41% on the term loan from 2024 to 2025. Income (loss) before income taxes increased $274.6 million, or 100.2%, from a loss of $274.1 million in 2024 to income of $0.5 million in 2025. The main drivers of this change in income from operations are described in the discussion above. ​ 50 Table of Contents Quarterly coal sales and cost data follow on a segment basis (in thousands, except for per ton data and wash plant recovery percentage): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ All Mines 1st 2025 ​ ​ ​ 2nd 2025 ​ ​ ​ 3rd 2025 ​ ​ ​ 4th 2025 ​ ​ ​ T4Qs Tons produced ​ 1,020 ​ 1,059 ​ 1,034 ​ 905 ​ 4,018 Tons sold ​ 1,071 ​ 890 ​ 1,355 ​ 995 ​ 4,311 Wash plant recovery in % ​ 64 % 66 % 64 % 57 % ​ Capex (Coal Operations) ​ $ 6,244 ​ $ 5,793 ​ $ 6,873 ​ $ 6,449 ​ $ 25,359 Capex per ton sold (Coal Operations) ​ $ 5.83 ​ $ 6.51 ​ $ 5.07 ​ $ 6.48 ​ $ 5.88 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average cost per ton sold⁽ⁱ⁾ ​ $ 43.65 ​ $ 46.03 ​ $ 42.74 ​ $ 46.75 ​ $ 44.57 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ All Mines 1st 2024 ​ ​ ​ 2nd 2024 ​ ​ ​ 3rd 2024 ​ ​ ​ 4th 2024 ​ ​ ​ T4Qs Tons produced ​ 1,271 ​ 889 ​ 873 ​ 971 ​ 4,004 Tons sold ​ 1,214 ​ 849 ​ 926 ​ 875 ​ 3,864 Wash plant recovery in % ​ 60 % 59 % 60 % 62 % ​ Capex (Coal Operations) ​ $ 8,632 ​ $ 7,560 ​ $ 6,810 ​ $ 11,079 ​ $ 34,081 Capex per ton sold (Coal Operations) ​ $ 7.11 ​ $ 8.90 ​ $ 7.35 ​ $ 12.66 ​ $ 8.82 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average cost per ton sold⁽ⁱ⁾ ​ $ 51.65 ​ $ 49.94 ​ $ 52.22 ​ $ 43.25 ​ $ 49.51 i) Average cost per ton sold is calculated as the sum of the Coal Operation’s “Fuel”, “Other Operating and Maintenance Costs”, “Utilities” and “Labor” costs, divided by tons sold for the respective period in this table. Coal Operations costs are presented in the “Discussion and Analysis of our Reportable Segments” above. During the fourth quarter of 2024, the Company made certain reclassification adjustments to other operating and maintenance costs and depreciation, depletion and amortization . Presentation of Consolidated Information The following tables presenting our quarterly results of operations should be read in conjunction with the consolidated financial statements and related notes included in Item 8 of this Form 10-K. We have prepared the unaudited information on the same basis as our audited consolidated financial statements. Our operating results for any quarter are not necessarily indicative of results for any future quarters or for a full year. The tables present our unaudited quarterly results of operations for the eight quarters ended December 31, 2025, and include all adjustments, consisting only of normal recurring adjustments, that we consider necessary for fair presentation of our consolidated operating results for the quarters presented. In the fourth quarter of 2024, the Company made certain reclassifications that reduced “other operating and maintenance costs” and increased “depreciation, depletion and amortization” for certain assets with a useful life of one to three years. The entire adjustment is reflected in the fourth quarter of 2024. Previous interim periods and prior year periods were not adjusted as the amounts were not material. The amounts recognized in the fourth quarter of 2024 that are related to the first, second and third quarters of 2024 were $2.1 million, $2.6 million and $1.7 million, respectively. 51 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Mar-31 ​ ​ ​ Jun-30 ​ ​ ​ Sep-30 ​ ​ ​ Dec-31 ​ ​ ​ ​ ​ ​ ​ 2025 ​ 2025 ​ 2025 ​ 2025 ​ Total 2025 ​ ​ (in thousands, except per share information) SALES AND OPERATING REVENUES: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Electric sales ​ $ 85,943 ​ $ 59,976 ​ $ 93,235 ​ $ 71,583 ​ $ 310,737 Coal sales ​ 30,185 ​ 38,147 ​ 51,256 ​ 29,067 ​ 148,655 Other revenues ​ 1,596 ​ 4,702 ​ 2,066 ​ 1,710 ​ 10,074 Total revenue ​ 117,724 ​ 102,825 ​ 146,557 ​ 102,360 ​ 469,466 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ EXPENSES: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fuel ​ 15,210 ​ ​ 15,063 ​ 27,119 ​ 6,462 ​ 63,854 Other operating and maintenance costs ​ ​ 28,389 ​ ​ 28,955 ​ ​ 44,415 ​ ​ 27,487 ​ ​ 129,246 Cost of purchased power ​ ​ 6,840 ​ ​ 2,172 ​ ​ 2,074 ​ ​ 9,806 ​ ​ 20,892 Utilities ​ ​ 4,152 ​ ​ 4,507 ​ ​ 4,543 ​ ​ 3,599 ​ ​ 16,801 Labor ​ ​ 27,029 ​ ​ 26,799 ​ ​ 27,574 ​ ​ 29,276 ​ ​ 110,678 Depreciation, depletion and amortization ​ 14,977 ​ ​ 5,542 ​ 9,142 ​ 11,561 ​ 41,222 ARO accretion ​ 427 ​ ​ 437 ​ 446 ​ 454 ​ 1,764 Exploration costs ​ 21 ​ ​ 98 ​ 38 ​ 59 ​ 216 General and administrative ​ 6,825 ​ ​ 7,501 ​ 4,770 ​ 7,130 ​ 26,226 Gain on disposal or abandonment of assets, net ​ ​ (21) ​ ​ (55) ​ ​ (2,334) ​ ​ (79) ​ ​ (2,489) Total operating expenses ​ 103,849 ​ 91,019 ​ 117,787 ​ 95,755 ​ 408,410 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ INCOME (LOSS) FROM OPERATIONS ​ 13,875 ​ 11,806 ​ 28,770 ​ 6,605 ​ 61,056 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest income ​ ​ 63 ​ ​ 64 ​ ​ 289 ​ ​ 186 ​ ​ 602 Interest expense ​ (3,723) ​ (3,819) ​ (4,927) ​ (4,427) ​ (16,896) Loss on extinguishment of debt ​ — ​ — ​ — ​ (608) ​ (608) Equity method investment income (loss) ​ (236) ​ 197 ​ (248) ​ (163) ​ (450) INCOME (LOSS) BEFORE INCOME TAXES ​ 9,979 ​ 8,248 ​ 23,884 ​ 1,593 ​ 43,704 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ INCOME TAX EXPENSE (BENEFIT): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Current ​ — ​ ​ — ​ ​ — ​ ​ — ​ — Deferred ​ — ​ ​ — ​ ​ — ​ ​ 1,833 ​ 1,833 Total income tax expense (benefit) ​ — ​ — ​ — ​ 1,833 ​ 1,833 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NET INCOME (LOSS) ​ $ 9,979 ​ $ 8,248 ​ $ 23,884 ​ $ (240) ​ $ 41,871 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NET INCOME (LOSS) PER SHARE: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Basic ​ $ 0.23 ​ $ 0.19 ​ $ 0.56 ​ $ (0.01) ​ $ 0.98 Diluted ​ $ 0.23 ​ $ 0.19 ​ $ 0.55 ​ $ (0.01) ​ $ 0.96 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ WEIGHTED AVERAGE SHARES OUTSTANDING: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Basic ​ 42,619 ​ ​ 42,619 ​ ​ 43,007 ​ ​ 43,119 ​ ​ 42,932 Diluted ​ 43,462 ​ ​ 43,048 ​ ​ 43,434 ​ ​ 43,119 ​ ​ 43,432 ​ ​ 52 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Mar-31 ​ ​ ​ Jun-30 ​ ​ ​ Sep-30 ​ ​ ​ Dec-31 ​ ​ ​ ​ ​ ​ ​ ​ ​ 2024 ​ 2024 ​ 2024 ​ 2024 ​ Total 2024 ​ ​ (in thousands, except per share information) SALES AND OPERATING REVENUES: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Electric sales ​ $ 60,681 ​ $ 59,465 ​ $ 71,715 ​ $ 69,666 ​ $ 261,527 Coal sales ​ 49,630 ​ 32,801 ​ 31,662 ​ 23,355 ​ 137,448 Other revenues ​ 1,175 ​ 992 ​ 1,334 ​ 1,683 ​ 5,184 Total revenue ​ 111,486 ​ 93,258 ​ 104,711 ​ 94,704 ​ 404,159 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ EXPENSES: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fuel ​ 8,059 ​ ​ 10,439 ​ 13,176 ​ 17,669 ​ 49,343 Other operating and maintenance costs ​ ​ 37,482 ​ ​ 35,912 ​ ​ 33,320 ​ ​ 11,650 ​ ​ 118,364 Cost of purchased power ​ ​ 1,926 ​ ​ 2,619 ​ ​ 3,149 ​ ​ 3,194 ​ ​ 10,888 Utilities ​ ​ 4,374 ​ ​ 3,396 ​ ​ 3,185 ​ ​ 4,959 ​ ​ 15,914 Labor ​ ​ 35,168 ​ ​ 26,555 ​ ​ 26,721 ​ ​ 27,720 ​ ​ 116,164 Depreciation, depletion and amortization ​ 15,443 ​ ​ 13,649 ​ 13,838 ​ 22,696 ​ 65,626 ARO accretion ​ 399 ​ ​ 399 ​ 410 ​ 420 ​ 1,628 Exploration costs ​ 70 ​ ​ 47 ​ 62 ​ 81 ​ 260 General and administrative ​ 5,944 ​ ​ 7,803 ​ 6,471 ​ 6,309 ​ 26,527 (Gain) loss on disposal or abandonment of assets, net ​ ​ (24) ​ ​ (222) ​ ​ (290) ​ ​ 486 ​ ​ (50) Asset impairment ​ ​ — ​ ​ — ​ ​ — ​ ​ 215,136 ​ ​ 215,136 Settlement of litigation ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,750 ​ ​ 2,750 Total operating expenses ​ 108,841 ​ 100,597 ​ 100,042 ​ 313,070 ​ 622,550 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ INCOME (LOSS) FROM OPERATIONS ​ 2,645 ​ (7,339) ​ 4,669 ​ (218,366) ​ (218,391) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest income ​ ​ 88 ​ ​ 53 ​ ​ 43 ​ ​ 51 ​ ​ 235 Interest expense ​ (3,937) ​ (3,735) ​ (2,692) ​ (3,486) ​ (13,850) Loss on extinguishment of debt ​ (853) ​ (1,937) ​ — ​ — ​ (2,790) Equity method investment income (loss) ​ (249) ​ (257) ​ (234) ​ (6) ​ (746) INCOME (LOSS) BEFORE INCOME TAXES ​ (2,306) ​ (13,215) ​ 1,786 ​ (221,807) ​ (235,542) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ INCOME TAX EXPENSE (BENEFIT): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Current ​ — ​ ​ — ​ ​ — ​ ​ (169) ​ (169) Deferred ​ (610) ​ ​ (3,011) ​ ​ 232 ​ ​ (5,846) ​ (9,235) Total income tax expense (benefit) ​ (610) ​ (3,011) ​ 232 ​ (6,015) ​ (9,404) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NET INCOME (LOSS) ​ $ (1,696) ​ $ (10,204) ​ $ 1,554 ​ $ (215,792) ​ $ (226,138) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NET INCOME (LOSS) PER SHARE: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Basic ​ $ (0.05) ​ $ (0.27) ​ $ 0.04 ​ $ (5.06) ​ $ (5.72) Diluted ​ $ (0.05) ​ $ (0.27) ​ $ 0.04 ​ $ (5.06) ​ $ (5.72) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ WEIGHTED AVERAGE SHARES OUTSTANDING: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Basic ​ 34,816 ​ ​ 37,879 ​ ​ 42,598 ​ ​ 42,617 ​ ​ 39,504 Diluted ​ 34,816 ​ ​ 37,879 ​ ​ 43,018 ​ ​ 42,617 ​ ​ 39,504 ​ 53 Table of Contents Income Taxes Our effective tax rate (“ETR”) is approximately 4% for the years ended December 31, 2025 and 2024. For the year ended December 31, 2025, 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 8. Financial Statements - Note 8 - Stock Compensation Plans” in the Consolidated Financial Statements for a discussion of RSUs. LIQUIDITY AND CAPITAL RESOURCES Sources and Uses of Cash We are a holding company that is dependent on the capital resources of our subsidiaries to satisfy our liquidity requirements at the corporate level. Each of our significant operating subsidiaries typically generate cash from operating activities, but our ability to access the liquidity of these and other subsidiaries may be limited by tax and legal considerations, and other factors. Cash and cash equivalents Hallador had $15.4 million of cash and restricted cash as of December 31, 2025 versus $12.2 million at December 31, 2024. Liquidity of Hallador Our short-term sources of corporate liquidity include (i) cash and cash equivalents held by Hallador, (ii) cash provided by operations, (iii) interest income received on our cash and cash equivalents and, (iv) borrowing availability under our bank facility. For the details of the borrowing availability under our bank facility, see “Item 8. Financial Statements - Note 4 – Bank Debt” to our Consolidated Financial Statements. The liquidity of Hallador generally is used to fund (i) capital expenditures, (ii) debt service requirements and (iii) general and administrative expenses, as well as to settle certain obligations that are not included on our December 31, 2025 consolidated balance sheet. In this regard, we have commitments related to (a) leases of railcars that qualify for the short-term lease exception and (b) certain operating costs associated with our Electric Operations and our Coal Operations. From time to time, we may also require liquidity in connection with (i) acquisitions and other investment opportunities, (ii) the satisfaction of contingent liabilities, (iii) capital distributions to Hallador equity owners, (iv) the repayment of third-party debt, or (v) income tax payments. No assurance can be given that any external funding would be available to us on favorable terms, or at all. Consolidated Statement of Cash Flows Summary. The 2025 and 2024 consolidated statements of cash flows are summarized as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ ​ ​ ​ 12/31/2025 ​ ​ ​ 12/31/2024 Change ​ (in millions) ​ ​ Net cash provided by operating activities ​ 81,134 ​ 65,934 ​ 15,200 Net cash used in investing activities ​ (66,547) ​ (46,470) ​ (20,077) Net cash used in financing activities ​ (11,368) ​ (14,434) ​ 3,066 Increase in cash, cash equivalents, and restricted cash 3,219 5,030 ​ (1,811) 54 Table of Contents Operating Activities. The increase in net cash provided by our operating activities is primarily attributable to the combination of (i) an increase in cash provided by our Adjusted EBITDA and related working capital items, (ii) new prepaid forward sales contracts in 2025, and (iii) lower cash payments of interest. Consolidated Adjusted EBITDA is a non-GAAP measure, which investors should view as a supplement to, and not a substitute for, GAAP measures of performance included in our consolidated statements of operations. Investing Activities. The change in net cash used by our investing activities is primarily attributable to the net effect of (i) an increase in our capital expenditures of $15.8 million (ii) a $1.1 million decrease in the proceeds from sales of equipment, and (iii) a $3.2 million decrease in proceeds from held-for-sale investments. For the year ended December 31, 2025, our Capex was $69.2 million allocated as follows (in millions): ​ ​ ​ ​ Oaktown ​ 25.4 Merom ​ 25.5 Merom – ELG ​ ​ 4.7 ERAS Project ​ 13.6 Capex per the Condensed Consolidated Statements of Cash Flows ​ $ 69.2 We expect our 2026 capital expenditures to modestly increase as compared to our 2025 capital expenditures, excluding any impacts of the ERAS project. The actual amount of our 2026 capital expenditures may vary from our expectations for a variety of reasons, including (i) changes in (a) the competitive or regulatory environment, (b) business plans, or (c) our expected future operating results and (ii) the availability of sufficient capital. Accordingly, no assurance can be given that our actual capital expenditures will not vary materially from our expectations. Financing Activities. The decrease in net cash used in our financing activities is primarily attributable to the net effect of (i) a decrease in cash used of $33.5 million due to lower net repayments of debt, (ii) a reduction in cash provided from the issuance of equity securities of $21.0 million, and (iii) a decrease in cash provided of $5.1 million in proceeds from sales and leaseback arrangements. Capitalization We seek to maintain our debt at levels that provide for equity returns without assuming undue risk. Our ability to service or refinance our debt and to maintain compliance with the leverage covenants in our credit agreement is dependent primarily on our ability to maintain or increase the Adjusted EBITDA of our consolidated businesses, maintain adequate liquidity and coverage of fixed charges, and to achieve adequate returns on our capital expenditures and acquisitions. Consolidated Adjusted EBITDA is a non-GAAP measure, which investors should view as a supplement to, and not a substitute for, GAAP measures of performance included in our consolidated statements of operations. In addition, our ability to obtain additional debt financing is limited by the incurrence-based leverage covenants contained in our debt instruments. For example, if the Adjusted EBITDA of our business was to decline, our ability to obtain additional debt could be limited. As of December 31, 2025, our bank debt was $30.0 million, which was repaid subsequent to year-end as further described below. On September 27, 2024, the Company executed the First Amendment (“First Amendment”) to the Fourth Amended and Restated Credit Agreement, dated as of August 2, 2023 (as amended, the “Credit Agreement”), with PNC Bank, National Association (in its capacity as administrative agent, "PNC"), which was accounted for as a debt modification. The primary purpose of the First Amendment was to provide the Company with short-term covenant relief to pursue additional liquidity. The First Amendment provided for additional flexibility for the Company to enter into prepaid forward power sale contracts, provided that the Company repaid outstanding term loans under the Credit Agreement (“Term Loan”) with proceeds received from certain eligible power purchase agreements, up to a maximum of $20.0 million. These required prepaid forward power sale Term Loan repayments, if any, would take the place of the $6.5 million quarterly Term Loan payments. On June 27, 2025, the Company executed the Third Amendment (“Third Amendment”) to our Credit Agreement, which was accounted for as a debt modification. The primary purpose of the Third Amendment was to provide additional 55 Table of Contents operating flexibility for the remainder of 2025 by redefining covenants, deferring certain covenants until the third quarter of 2025 and moving our October 2025 payment to January 2026. The Third Amendment provided for additional flexibility for the Company to enter into prepaid forward power sale contracts, provided that the Company maintained one hundred percent of the outstanding aggregate principal balance of the Term Loan as a compensating balance. As part of the Third Amendment, the required October 2025 principal payment of $6.0 million and the January 2026 principal payment of $6.5 million, pursuant to the Term Loan, were both due in January 2026. The balance of the Term Loan was paid off in November 2025. On March 5, 2026, Hallador entered into a credit agreement with Texas Capital Bank and Old National Bank, among others, that replaces the Credit Agreement with PNC Bank and includes a $75.0 million revolving credit facility (the "New Revolving Credit Facility") and a $45.0 million delayed draw term loan (the "Delayed Draw Term Loan", and together with the New Revolving Credit Facility, the "New Credit Facility"). The New Credit Facility bears interest with margins ranging from 2.25% to 3.75% above SOFR or the applicable base rate, subject to a SOFR floor of 1.00%. The applicable margin is determined based upon the Company's leverage ratio and the type of loan drawn. The New Credit Facility includes a commitment fee of 0.50% on any unused portions of the New Revolving Credit Facility. If the Delayed Draw Term Loan occurs, which is subject to meeting certain conditions, the principal balance of the Delayed Draw Term Loan shall be due and payable in equal quarterly installments of 2.5% of the original principal amount of such Delayed Draw Term Loan with a final payment of the remaining balance upon maturity. The New Credit Facility matures on March 5, 2029, and is collateralized by substantially all our assets. When drawn, the proceeds from the New Credit Facility may be used for ongoing working capital and general corporate purposes. Liquidity at December 31, 2025 excludes the availability under the New Credit Facility. See “ Item 8. Financial Statements - Note 4 – Bank Debt ” to our Consolidated Financial Statements for additional discussion about our bank debt and related liquidity. Off-Balance Sheet Arrangements 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 $17.8 million, including $6.2 million at Merom, presented as asset retirement obligations (ARO) in our accompanying consolidated balance sheets. In the event we are not able to perform reclamation, we have surety bonds in place totaling $30.9 million to cover ARO. CRITICAL ACCOUNTING ESTIMATES In connection with the preparation of our consolidated financial statements, we make estimates and assumptions that affect the reported amounts of assets and liabilities, revenue and expenses and related disclosure of contingent assets and liabilities. Critical accounting policies are defined as those policies that are reflective of significant judgments, estimates and uncertainties, which would potentially result in materially different results under different assumptions and conditions. We believe the following accounting policies are critical in the preparation of our consolidated financial statements because of the judgment necessary to account for these matters and the significant estimates involved, which are susceptible to change: ● estimates of coal reserves; ● asset retirement obligations; ● income tax accounting; and ● impairment of long-lived assets. Estimates of Coal Reserves 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 56 Table of Contents 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. Asset Retirement Obligations 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, reclamation of refuse areas, slurry ponds and our landfill. 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. Income Tax Accounting We are required to estimate the amount of income taxes for the current year and the deferred tax assets and liabilities for the future tax consequences of differences between the financial statement carrying amounts and income tax basis of assets and liabilities and the expected benefits of utilizing net operating losses and tax credit carryforwards, using enacted tax rates for the year in which those temporary differences are expected to be recovered or settled. This process requires our management to make assessments regarding the timing and probability of the ultimate tax impact of such items. 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 provision 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. Impairment of Long-lived Assets 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 analysis 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. 57 Table of Contents