HALLADOR ENERGY CO 10-Q

ITEM 2. 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 and the discussion and analysis included in our 2025 10-K, is intended to assist in providing an understanding of changes in our results of operations and financial condition and is organized as follows: • Forward-Looking Statements. This section provides a description of certain factors that could cause actual results or events to differ materially from anticipated results or events. • Overview. This section provides a general description of our business and recent events. • Material Changes in Results of Operations. This section provides an analysis of our results of operations for the three and six months ended June 30, 2026 and 2025. • Material Changes in Financial Condition. This section provides an analysis of our liquidity and our condensed consolidated statements of cash flows. The capitalized terms used below have been defined in the notes to our condensed consolidated financial statements. In the following text, the terms “we,” “our,” “the Company” and “us” may refer, as the context requires, to Hallador Energy Company (“Hallador”) or collectively to Hallador and its subsidiaries. Unless otherwise indicated, operational data is presented as of June 30, 2026. FORWARD-LOOKING STATEMENTS Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” These statements are based on our beliefs as well as assumptions made by, and information currently available to us. When used in this document, the words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “may,” “project,” “will,” and similar expressions identify forward-looking statements. Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements. These statements reflect our current views with respect to future events and are subject to numerous assumptions that we believe are open to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ from those in the forward-looking statements are: • changes in macroeconomic and market conditions and market volatility, and the impact of such changes and volatility on our financial position; • fluctuations in weather, natural gas and electricity commodity costs, inflation and economic conditions that impact demand of our customers and our operating results; • the outcome or escalation of current international hostilities; • changes in competition, or changes in electricity, natural gas or coal prices, demand, and availability which could affect our operating results and cash flows; • risks associated with the expansion of our operations and properties; • risks relating to our ability to fund and perform our obligations under the Asset Purchase Agreement (the "APA") with Energy World Corporation Ltd. for the acquisition of turbine equipment, including our ability to secure financing for the remaining purchase price and related costs on a timely basis or at all, and the risk of default, forfeiture of amounts paid, or termination of the related agreements if we are unable to do so; • risks relating to the international and domestic transportation, refurbishment, and delivery of the turbine equipment acquired under the APA, including delays, damage or loss in transit, and costs that exceed our current estimates; • risks that we may be unable to deploy the turbine equipment acquired under the APA as planned, including because the Midcontinent Independent System Operator (“MISO”) does not approve our Expedited Resource Addition Study (“ERAS”) application or the related expansion project does not otherwise proceed, which could 20 Table of Contents require us to sell the project together with the equipment or sell the equipment on a standalone basis, potentially at a loss; • risks relating to our ability to participate in the MISO ERAS program, which ultimately requires the approval of MISO of our application and is a capital intensive project subject to construction, operational, financial, regulatory and legal risks that could impact the project’s viability and/or timeline; • risks relating to our ability to secure agreements in support of the development and construction of planned projects, including the expansion of the Merom Generating Station through the ERAS program; • legislation, regulations, administrative actions (e.g., executive orders), and court decisions and interpretations thereof, including those relating to the environment and the release of greenhouse gases (“GHG”), mining, miner health and safety, and health care, as well as those relating to data privacy protection; • deregulation of the electric utility industry or the effects of any adverse change in the coal industry, electric utility industry, or general economic conditions; • dependence on significant or long-term customer contracts, including renewing customer contracts upon expiration of existing contracts; • changes in the geopolitical environment in industries in which our customers operate; • changes in attitude toward environmental, social, and governance (“ESG”) matters among regulators, investors and parties with which we do business; • the effect of changes in taxes or tariffs and other trade measures, including uncertainty regarding tariffs on imports into the United States, which could impact the Company’s procurement and sourcing strategies; • risks relating to inflation and increasing interest rates; • liquidity constraints, including due to restrictions contained in our debt agreements or other arrangements and those resulting from any future unavailability of financing; • customer bankruptcies, a decline in customer creditworthiness, or customer cancellations or breaches to existing contracts, including failures to make payments when due; • customer delays or failure to take coal or electricity under contracts; • adjustments made in price, volume or terms to existing coal or electricity contracts; • our productivity levels and margins earned on our coal or electricity sales; • supply chain disruptions and changes in equipment, raw material, service or labor costs or availability, including due to inflationary pressures; • changes in the availability of skilled labor; • our ability to maintain satisfactory relations with our employees; • increases in labor costs, adverse changes in work rules, or cash payments or projections associated with workers’ compensation claims; • increases in transportation costs and risk of transportation delays or interruptions; • operational interruptions due to geologic, permitting, labor, weather-related or other factors, including challenges in operating an aging coal-fired power plant; • risks associated with major mine-related or other accidents, mine fires, mine floods or other interruptions, including unanticipated operating conditions and other events that are not within our control; • results of litigation, including claims not yet asserted; • difficulty maintaining our surety bonds for mine reclamation; • decline in or change in the coal industry’s share of electricity generation, including as a result of environmental concerns related to coal mining and combustion and the cost and perceived benefits of other sources of electricity, such as natural gas, nuclear energy, and renewable fuels; • risks resulting from natural disasters; • difficulty in making accurate assumptions and projections regarding landfill and mine reclamation; • uncertainties in estimating and replacing our coal reserves; 21 Table of Contents • the impact of current and potential changes to federal or state tax rules and regulations, including the effects of the One Big Beautiful Bill Act (“OBBBA”) or a loss or reduction of benefits from certain tax deductions and credits; • difficulty obtaining commercial property insurance; • evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions; • difficulty in making accurate assumptions and projections regarding future revenues and costs associated with equity investments in companies we do not control; and • other factors, including those discussed in “Item 1A. Risk Factors” in our Annual Report on Form 10-K. If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement. When considering forward-looking statements, you should also keep in mind the risk factors described in “Item 1A. Risk Factors” in our Annual Report on Form 10-K. The risk factors could also cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments, unless required by law. You should consider the information above when reading any forward-looking statements contained in this Quarterly Report on Form 10-Q; other reports filed by us with the U.S. Securities and Exchange Commission (“SEC”); our press releases; our website www.halladorenergy.com and written or oral statements made by us or any of our officers or other authorized persons acting on our behalf. 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 include Hallador Power which provides accredited capacity and energy to utilities and other energy market participants through its MISO interconnection, and Sunrise which 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 (“Sunrise Energy”) and Oaktown Gas, LLC (“Oaktown Gas”), 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 system, 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 Power Purchase Agreements (“PPA”) and other bilateral transactions. 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. 22 Table of Contents Coal. Sunrise, the Company’s wholly-owned mining subsidiary, mines coal from reserves found in the Illinois Basin (“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. 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 capacity 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 diversification, durability, scale, and geographic expansion opportunities to our Electric Operations. While these opportunities 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 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 “Material Changes in Financial Condition — Capitalization” below, we also seek to maintain our debt at levels that provide for attractive equity returns without assuming undue risk. Recent Developments Turbine Equipment Acquisition. On May 30, 2026, we entered into an APA with Energy World Corporation Ltd. to acquire approximately 460 MW of Siemens gas turbines, generators, a steam turbine, and ancillary equipment for a total purchase price of $350.0 million. We expect to incur approximately $100.0 million of additional costs for transportation, refurbishment, insurance, and logistics in connection with the delivery of the equipment. The equipment supports our proposed expansion of generation capacity through MISO's ERAS program. We retain the flexibility to determine the path that best creates value for shareholders, including advancing the full project, selling the project together with the equipment, or selling the equipment on a standalone basis. See “ Note 14 — Commitments and Contingencies” to the condensed consolidated financial statements and “Liquidity and Capital Resources” below for additional information. 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 system, 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. ​ 23 Table of Contents MATERIAL CHANGES IN RESULTS OF OPERATIONS Our contracted forward sales for accredited capacity, energy, and coal are detailed below with estimated revenue from forward sales of $2.4 billion as of June 30, 2026. Forward Sales Position * ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2026 ​ ​ ​ 2027 ​ ​ ​ 2028 ​ ​ ​ 2029 ​ 2030 ​ 2031 - 2040 ​ ​ ​ Total Power ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Accredited Capacity ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average daily contracted accredited capacity MW ​ 765 ​ 789 ​ 768 ​ 608 ​ 500 ​ 500 ​ ​ Average contracted accredited capacity price per MWd ​ $ 249 ​ $ 262 ​ $ 324 ​ $ 461 ​ $ 480 ​ $ 480 ​ ​ Contracted accredited capacity revenue (in millions) ​ $ 34.99 ​ $ 75.31 ​ $ 90.95 ​ $ 102.37 ​ $ 87.54 ​ $ 824.78 ​ $ 1,215.94 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Energy ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Contracted MWh (in millions) ​ 2.59 ​ 3.59 ​ 1.92 ​ 0.71 ​ ​ — ​ ​ — ​ 8.81 Average contracted price per MWh ​ $ 44.15 ​ $ 44.64 ​ $ 45.08 ​ $ 40.75 ​ $ — ​ $ — ​ ​ ​ Contracted revenue (in millions) ​ $ 114.35 ​ $ 160.26 ​ $ 86.55 ​ $ 28.93 ​ $ — ​ $ — ​ $ 390.09 Total Accredited Capacity & Energy Revenue (in millions) ​ $ 149.34 ​ $ 235.57 ​ $ 177.50 ​ $ 131.30 ​ $ 87.54 ​ $ 824.78 ​ $ 1,606.03 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Coal ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Priced tons - 3rd party (in millions) ​ 1.37 ​ 2.30 ​ 0.50 ​ ​ — ​ ​ — ​ ​ — ​ 4.17 Avg price per ton - 3rd party ​ $ 55.72 ​ $ 56.80 ​ $ 59.00 ​ ​ — ​ ​ — ​ ​ — ​ ​ Contracted coal revenue - 3rd party (in millions) ​ $ 76.34 ​ $ 130.64 ​ $ 29.50 ​ $ — ​ $ — ​ $ — ​ $ 236.48 TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED ​ $ 225.68 ​ $ 366.21 ​ $ 207.00 ​ $ 131.30 ​ $ 87.54 ​ $ 824.78 ​ $ 1,842.51 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Priced tons - Intercompany (in millions) ​ 1.87 ​ 1.50 ​ 2.02 ​ 2.02 ​ 2.02 ​ — ​ 9.43 Avg price per ton - Intercompany ​ $ 51.00 ​ $ 55.00 ​ $ 56.00 ​ ​ 57.00 ​ ​ 58.00 ​ ​ — ​ ​ Contracted coal revenue - Intercompany (in millions) ​ $ 95.37 ​ $ 82.50 ​ $ 113.12 ​ $ 115.14 ​ $ 117.16 ​ $ — ​ $ 523.29 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT ​ $ 321.05 ​ $ 448.71 ​ $ 320.12 ​ $ 246.44 ​ $ 204.70 ​ $ 824.78 ​ $ 2,365.80 * Actual revenue related to forward sales positions may differ materially for various reasons, including unit contingencies, price adjustment features for coal quality and cost escalations, volume optionality provisions, including rollover of unfulfilled coal commitments into future periods, and potential force majeure events. Certain contracted forward sales positions included above are subject to approval by the Indiana Utility Regulatory Commission. Forward sales figures in the 2026 column are for the period from July 1, 2026 through December 31, 2026. 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. 24 Table of Contents 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 and Oaktown Gas, which we account for using the equity method. Electric Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended June 30, ​ Six Months Ended June 30, ​ ​ 2026 ​ 2025 ​ 2026 ​ 2025 ​ ​ (in thousands) ​ (in thousands) Delivered Energy ​ $ 40,901 ​ $ 44,132 ​ $ 93,144 ​ $ 116,268 Accredited Capacity Revenue ​ ​ 18,608 ​ ​ 15,844 ​ ​ 34,142 ​ ​ 29,651 Electric Sales ​ $ 59,509 ​ $ 59,976 ​ $ 127,286 ​ $ 145,919 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fuel ​ $ (25,263) ​ $ (21,328) ​ $ (52,790) ​ $ (59,399) Other Operating Costs (1) ​ ​ - ​ ​ (1) ​ ​ (29) ​ ​ (9) Other Operating and Maintenance Costs (2) ​ ​ (16,305) ​ ​ (10,707) ​ ​ (25,159) ​ ​ (15,234) Cost of Purchased Power ​ ​ (8,633) ​ ​ (2,172) ​ ​ (23,496) ​ ​ (9,012) Utilities ​ ​ (1,281) ​ ​ (1,383) ​ ​ (4,096) ​ ​ (2,059) Labor ​ ​ (8,622) ​ ​ (7,639) ​ ​ (16,751) ​ ​ (15,782) General and Administrative ​ ​ (1,481) ​ ​ (1,129) ​ ​ (2,791) ​ ​ (2,664) Segment EBITDA ​ ​ (2,076) ​ ​ 15,617 ​ ​ 2,174 ​ ​ 41,760 Other Operating Revenue ​ ​ 231 ​ ​ 3,115 ​ ​ 368 ​ ​ 3,202 Depreciation, Depletion and Amortization ​ ​ (5,485) ​ ​ (5,164) ​ ​ (11,868) ​ ​ (10,325) Asset Retirement Obligations Accretion ​ ​ (133) ​ ​ (123) ​ ​ (264) ​ ​ (243) Interest Income ​ ​ 38 ​ ​ 19 ​ ​ 74 ​ ​ 19 Interest Expense ​ ​ (2,416) ​ ​ (1,891) ​ ​ (5,363) ​ ​ (3,623) Income before Income Taxes ​ $ (9,841) ​ $ 11,573 ​ $ (14,879) ​ $ 30,790 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended June 30, ​ Six Months Ended June 30, ​ ​ 2026 ​ 2025 ​ 2026 ​ 2025 ​ ​ (in thousands) ​ (in thousands) ​ ​ (per MWh) ​ (per MWh) MWh Generated (in thousands) ​ ​ 797 ​ ​ 754 ​ ​ 1,735 ​ ​ 2,176 MWh Purchased (in thousands) ​ ​ 184 ​ ​ 84 ​ ​ 367 ​ ​ 216 MWh Sold (in thousands) ​ ​ 981 ​ ​ 838 ​ ​ 2,102 ​ ​ 2,392 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Delivered Energy ​ $ 41.69 ​ $ 52.66 ​ $ 44.31 ​ $ 48.61 Accredited Capacity Revenue ​ ​ 18.97 ​ ​ 18.91 ​ ​ 16.24 ​ ​ 12.40 Electric Sales ​ $ 60.66 ​ $ 71.57 ​ $ 60.55 ​ $ 61.01 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fuel ​ $ (25.75) ​ $ (25.45) ​ $ (25.11) ​ $ (24.83) Other Operating Costs (1) ​ ​ — ​ ​ — ​ ​ (0.01) ​ ​ — Other Operating and Maintenance Costs (2) ​ ​ (16.62) ​ ​ (12.78) ​ ​ (11.97) ​ ​ (6.37) Cost of Purchased Power ​ ​ (8.80) ​ ​ (2.59) ​ ​ (11.18) ​ ​ (3.77) Utilities ​ ​ (1.31) ​ ​ (1.65) ​ ​ (1.95) ​ ​ (0.86) Labor ​ ​ (8.79) ​ ​ (9.12) ​ ​ (7.97) ​ ​ (6.60) General and Administrative ​ ​ (1.51) ​ ​ (1.35) ​ ​ (1.33) ​ ​ (1.11) Segment EBITDA ​ ​ (2.12) ​ ​ 18.63 ​ ​ 1.03 ​ ​ 17.47 Other Operating Revenue ​ ​ 0.24 ​ ​ 3.72 ​ ​ 0.18 ​ ​ 1.34 Depreciation, Depletion and Amortization ​ ​ (5.59) ​ ​ (6.16) ​ ​ (5.65) ​ ​ (4.32) Asset Retirement Obligations Accretion ​ ​ (0.14) ​ ​ (0.15) ​ ​ (0.13) ​ ​ (0.10) Interest Income ​ ​ 0.04 ​ ​ 0.02 ​ ​ 0.04 ​ ​ 0.01 Interest Expense ​ ​ (2.46) ​ ​ (2.26) ​ ​ (2.55) ​ ​ (1.51) Income before Income Taxes ​ $ (10.03) ​ $ 13.80 ​ $ (7.08) ​ $ 12.89 (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 included in fuel and other operating costs. 25 Table of Contents ​ Q2 2026 vs. Q2 2025 ​ Segment operating revenues from electric operations decreased $0.5 million, or 0.8%, compared to the second quarter of 2025, attributable to a $3.2 million decrease in sales of delivered energy that was partially offset by a $2.8 million increase in accredited capacity revenue. The price per MWh for delivered energy decreased 20.8% year-over-year from $52.66 for the three-month period ended June 30, 2025 to $41.69 in 2026, primarily attributable to contract mix, driven by increased deliveries under lower-priced prepaid forward sales contracts. Our Electric Operations generated a slightly increased quantity of MWh and purchased an additional 0.1 million MWh for resale resulting in a net increase of energy sales of 0.1 million MWh, an increase of 17.1% compared to the second quarter of 2025. The annual planned major maintenance outages had a significant impact on the total MWh generated during both the three months ended June 30, 2026 and 2025. Accredited capacity revenue increased 17.4% to $18.6 million for the three-month period ended June 30, 2026 from $15.8 million in the comparable prior year period. Fuel costs on a segment basis increased $3.9 million, or 18.4%, from the second quarter of 2025. The increase is due to electric power generation increasing by 5.7% coupled with an increase in the cost of coal consumed of 2.7%, from $53.38 per ton in 2025 to $54.82 per ton in 2026 along with an increase in tons consumed. Fuel costs on a consolidated basis were relatively unchanged from the second quarter of 2025 at $14.7 million, as fewer tons purchased from third parties, reflecting a heavier reliance on coal from Sunrise, offset a 6.0% increase in the average price per ton of coal purchased from third parties. Natural gas pricing did not impact the demand for coal, as the average spot price at Chicago citygate only increased by $0.02 per thousand cubic feet to $2.94 per thousand cubic feet in April 2026 compared to April 2025. The weather year-over-year had a muted impact on the demand for electricity. Other operating and maintenance costs increased $5.6 million, or 52.3%, from the second quarter of 2025. The increase was driven by increased maintenance activities in connection with the planned major maintenance outage. The impacted generating unit came back online in July 2026. Cost of purchased power increased $6.5 million, or 297.5%, from the second quarter of 2025. 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 economic net hourly purchases of power in the MISO market to satisfy our obligations, which we record as cost of purchased power. In 2026, we purchased an incremental 0.1 million MWh compared to 2025, an increase of 119.0% that was further impacted by the energy pricing dynamics at the time of the purchases. Labor expenses increased $1.0 million or 12.9% for the second quarter of 2026 versus the comparable period in 2025 driven by the impact of incremental maintenance efforts associated with the planned major maintenance outage in combination with annual wage increases. Other operating revenue decreased $2.9 million or 92.6% compared to the second quarter of 2025, which included $3.0 million of revenue received related to contractual negotiations on an exclusivity agreement that did not recur in 2026. Depreciation, depletion and amortization increased $0.3 million, or 6.2%, from the second quarter of 2025 as incremental depreciation from recent capital expenditures placed in service was only partially offset by lower depreciation expense from extending the estimated useful lives of the Merom Generating Station and related assets through 2040. This change was accounted for prospectively as a change in accounting estimate and decreased depreciation expense by $1.2 million for the three months ended June 30, 2026. See “Note 1 – Basis of Presentation” to the condensed consolidated financial statements for further information. Interest expense increased $0.5 million, or 27.8%, from the second quarter of 2025. The increase in our interest expense primarily relates to accretion on our prepaid delivered energy contracts that were entered into in 2024 and 2025. Hallador has not entered into any new prepaid delivered energy contracts in 2026. Income before income taxes decreased $21.4 million from $11.6 million of income before taxes in the second quarter of 2025 to a loss before income taxes of $9.8 million in the second quarter of 2026, which is attributable to the items described in the discussion above. 26 Table of Contents YTD 2026 vs. YTD 2025 ​ Segment operating revenues from electric operations for the six months ended June 30, 2026 decreased $18.6 million, or 12.8% compared to the first half of 2025, attributable to a $23.1 million decrease in sales of delivered energy partially offset by a $4.5 million increase in accredited capacity revenue. Our Electric Operations generated 0.4 million fewer MWh, but purchased an additional 0.2 million MWh for resale resulting in a net decrease of energy sales of 0.3 million MWh, a decrease of 12.1% compared to the first half of 2025. Lower plant availability in the first half of 2026 due to equipment issues at Merom had a significant impact on the total MWh generated. The impacted generating unit underwent a planned major maintenance outage beginning in May and the unit returned to operation in July. The price per MWh for delivered energy decreased 8.8% year-over-year from $48.61 for the six-month period ended June 30, 2025 to $44.31 in 2026. Accredited capacity revenue increased 15.1% to $34.1 million for the six-month period ended June 30, 2026 from $29.7 million in the comparable prior year period. Fuel costs on a segment basis decreased $6.6 million, or 11.1%, from the first half of 2025. The decrease is due to electric power generation falling by 0.4 million MWh, or 20.3%. We consumed 0.1 million fewer tons of coal on both a segment and consolidated basis in 2026 compared to 2025. The decrease in electric power generation was largely attributable to the equipment issues experienced during Q1 2026, which resulted in 0.4 million lower MWh generated during the six months ended June 30, 2026, compared to the same period in 2025. The decrease was partially offset by an increase in the cost of coal consumed from $53.65 per ton in 2025 to $54.69 per ton in 2026. Fuel costs on a consolidated basis were relatively unchanged from the first half of 2025 at $29.1 million down from $29.3 million in 2025. Other operating and maintenance costs increased $9.9 million, or 65.2%, from the first half of 2025. The increase was driven by increased maintenance activities attributable to the aforementioned equipment issues at Merom in combination with expenses from the planned major maintenance outage. The impacted generating unit returned to service in July 2026 . Cost of purchased power increased $14.5 million, or 160.7%, from the first half of 2025. 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 economic net hourly purchases of power in the MISO market to satisfy our obligations, which we record as cost of purchased power. In 2026, we purchased an incremental 0.2 million MWh compared to 2025, an increase of 69.9% that was further impacted by the energy pricing dynamics at the time of the purchases. Utilities expense increased $2.0 million, or 98.9%, compared to 2025, which was largely attributable to the frequency and timing of energy intensive start-ups of the generating units. Labor expenses increased $1.0 million, or 6.1% in the first half of 2026 versus the comparable period in 2025 driven by the impact of incremental maintenance efforts associated with planned major maintenance outage in combination with annual wage increases. Other operating revenue decreased $2.8 million or 88.5% compared to the first half of 2025. This decrease primarily reflects the $3.0 million exclusivity agreement fee received in the second quarter of 2025. Depreciation, depletion and amortization increased $1.5 million, or 14.9%, compared to the first half of 2025, driven by capital additions placed in service, partially offset by a $1.2 million decrease resulting from the change in the estimated useful life of the Merom Generating Station described above. Interest expense increased $1.7 million, or 48.0%, from the first half of 2025. The increase in our interest expense primarily relates to accretion on our prepaid delivered energy contracts that were entered into in 2024 and 2025. Hallador has not entered into any new prepaid delivered energy contracts in 2026. Income before income taxes decreased $45.7 million from $30.8 million of income before taxes in the first half of 2025 to a loss before taxes of $14.9 million in the first half of 2026, which is attributable to the items described in the discussion above. 27 Table of Contents Coal Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended June 30, ​ Six Months Ended June 30, ​ ​ 2026 ​ 2025 ​ 2026 ​ 2025 ​ ​ (in thousands) ​ (in thousands) Coal Sales ​ $ 50,874 ​ $ 45,529 ​ $ 97,286 ​ $ 100,303 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fuel ​ $ (786) ​ $ (434) ​ $ (1,314) ​ $ (990) Other Operating and Maintenance Costs ​ ​ (22,827) ​ ​ (18,247) ​ ​ (43,100) ​ ​ (42,101) Utilities ​ ​ (2,679) ​ ​ (3,124) ​ ​ (5,878) ​ ​ (6,600) Labor ​ ​ (20,190) ​ ​ (19,160) ​ ​ (39,449) ​ ​ (38,046) General and Administrative ​ ​ (2,218) ​ ​ (1,915) ​ ​ (4,429) ​ ​ (4,228) Segment EBITDA ​ ​ 2,174 ​ ​ 2,649 ​ ​ 3,116 ​ ​ 8,338 Other Operating Revenue ​ ​ 788 ​ ​ 1,363 ​ ​ 1,928 ​ ​ 2,624 Depreciation, Depletion and Amortization ​ ​ (4,401) ​ ​ (359) ​ ​ (8,605) ​ ​ (10,156) ARO Accretion ​ ​ (283) ​ ​ (314) ​ ​ (560) ​ ​ (621) Exploration Costs ​ ​ (287) ​ ​ (98) ​ ​ (371) ​ ​ (119) Gain on Disposal or Abandonment of Assets, Net ​ ​ (15) ​ ​ 55 ​ ​ 186 ​ ​ 76 Interest Income ​ ​ 240 ​ ​ 36 ​ ​ 351 ​ ​ 99 Interest Expense ​ ​ (133) ​ ​ (1,928) ​ ​ (941) ​ ​ (3,919) Income (Loss) before Income Taxes ​ $ (1,917) ​ $ 1,404 ​ $ (4,896) ​ $ (3,678) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended June 30, ​ Six Months Ended June 30, ​ ​ 2026 ​ 2025 ​ 2026 ​ 2025 ​ ​ (in thousands) ​ (in thousands) ​ ​ (per ton) ​ (per ton) Tons Sold (in thousands) ​ ​ 934 ​ 890 ​ ​ 1,788 ​ ​ 1,961 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Coal Sales ​ $ 54.47 ​ $ 51.16 ​ $ 54.41 ​ $ 51.15 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fuel ​ $ (0.84) ​ $ (0.49) ​ $ (0.73) ​ $ (0.50) Other Operating and Maintenance Costs ​ ​ (24.44) ​ ​ (20.50) ​ ​ (24.11) ​ ​ (21.47) Utilities ​ ​ (2.87) ​ ​ (3.51) ​ ​ (3.29) ​ ​ (3.37) Labor ​ ​ (21.62) ​ ​ (21.53) ​ ​ (22.06) ​ ​ (19.40) General and Administrative ​ ​ (2.37) ​ ​ (2.15) ​ ​ (2.48) ​ ​ (2.16) Segment EBITDA ​ ​ 2.33 ​ ​ 2.98 ​ ​ 1.74 ​ ​ 4.25 Other Operating Revenue ​ ​ 0.84 ​ ​ 1.53 ​ ​ 1.08 ​ ​ 1.34 Depreciation, Depletion and Amortization ​ ​ (4.71) ​ ​ (0.40) ​ ​ (4.81) ​ ​ (5.18) ARO Accretion ​ ​ (0.30) ​ ​ (0.35) ​ ​ (0.31) ​ ​ (0.32) Exploration Costs ​ ​ (0.31) ​ ​ (0.11) ​ ​ (0.21) ​ ​ (0.06) Gain on Disposal or Abandonment of Assets, Net ​ ​ (0.02) ​ ​ 0.06 ​ ​ 0.10 ​ ​ 0.04 Interest income ​ ​ 0.26 ​ ​ 0.04 ​ ​ 0.20 ​ ​ 0.05 Interest expense ​ ​ (0.14) ​ ​ (2.17) ​ ​ (0.53) ​ ​ (2.00) Loss on Extinguishment of Debt ​ ​ — ​ ​ — ​ ​ — ​ ​ — Income (Loss) before Income Taxes ​ $ (2.05) ​ $ 1.58 ​ $ (2.74) ​ $ (1.88) ​ Q2 2026 vs. Q2 2025 Segment operating revenue from coal operations (including intercompany sales to Merom) increased $5.3 million, or 11.7%, compared to the second quarter of 2025. The increase was driven by higher volume in combination with an increase in the average sales price for our coal. We sold 0.9 million tons of coal during the second quarter of 2026, an increase of 44,000 tons, or 4.9%, versus 2025. Our average sales price, on a segment basis, increased $3.31 per ton from $51.16 per ton to $54.47 per ton. The increased sales were driven by improved coal demand from Merom in preparation for summer, as Sunrise sold 59,000 incremental tons to Merom, partially offset by a 2.0% decrease in tons sold to third parties in the second quarter of 2026 compared to 2025. On a consolidated basis, third party sales increased $2.5 million, 28 Table of Contents or 6.4%, versus the second quarter of 2025, attributable to the 8.6% increase in our average third party price per ton, which more than offset a 2.0% decrease in tons sold to third parties. Other operating and maintenance costs increased $4.6 million, or 25.1%, which is largely attributable to higher mine expansion costs as well as the increase in total tons sold of 44,000, or 4.9%, versus the second quarter of 2025. Labor expenses increased $1.0 million, or 5.4%, from the second quarter of 2025, leading to a small increase in labor cost per ton sold of $0.09 per ton up to $21.62 per ton for the three months ended June 30, 2026. Depreciation, Depletion and Amortization increased by $4.0 million compared to the second quarter of 2025, largely as a result of a $4.8 million out-of-period adjustment recorded during the second quarter of 2025 due to an overstatement of depreciation, depletion and amortization expense in the first quarter of 2025. Interest expense decreased $1.8 million, or 93.1%, from $1.9 million for the three months ended June 30, 2025 to $0.1 million in 2026. The decrease is attributable to the paydown of the Company’s previous bank facility from $30.0 million at December 31, 2025, while the new bank facility is not held within the Coal Operations segment. Income before income taxes decreased by $3.3 million from income before income taxes of $1.4 million in the second quarter of 2025 to a loss before income taxes of $1.9 million in 2026. The main drivers of this change in income (loss) before income taxes are described in the discussion above. ​ YTD 2026 vs. YTD 2025 Segment operating revenue from coal operations (including intercompany sales to Merom) decreased $3.0 million, or 3.0%, compared to the six months ended June 30, 2025. The decrease was driven by lower volume partially offset by an increase in the average sales price for our coal. We sold 1.8 million tons of coal during the first six months of 2026, a decrease of 0.2 million tons, or 8.8%, versus 2025. Our average sales price, on a segment basis, increased $3.26 per ton from $51.15 per ton to $54.41 per ton. The decreased sales were driven by lower coal demand from Merom due to the aforementioned equipment issues. Sunrise sold 0.2 million fewer tons of coal to Merom, offset by a 2.0% increase in tons sold to third parties in the six months ended June 30, 2026 compared to 2025. On a consolidated basis, third party sales increased $7.3 million, or 10.8%, versus the first half of 2025 attributable to 2.0% more tons sold to third parties, supplemented by an 8.5% increase in our average third party price per ton. Other operating and maintenance costs increased $1.0 million, or 2.4%, which is attributable to higher mine expansion costs, offset by the decrease in total tons sold of 0.2 million, or 8.8%, versus the first six months of 2025. Labor expenses increased $1.4 million, or 3.7%, from the six months ended June 30, 2025; however, because tons sold declined 8.8%, labor cost per ton sold rose $2.66 to $22.06 per ton as production at the mine outpaced coal sales. Depreciation, Depletion and Amortization decreased by $1.6 million, or 15.3%, compared to the first six months of 2025. Interest expense decreased $3.0 million, or 76.0%, from $3.9 million for the six months ended June 30, 2025 to $0.9 million in 2026. The decrease is attributable to the paydown of the Company’s previous bank facility from $30.0 million at December 31, 2025, while the new bank facility is not held within the Coal Operations segment. Loss before income taxes increased by $1.2 million, or 33.1% compared to the first six months of 2025. The main drivers of this change in loss before income taxes are described in the discussion above. ​ 29 Table of Contents 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 2025 ​ ​ ​ 4th 2025 ​ ​ ​ 1st 2026 ​ ​ ​ 2nd 2026 ​ ​ ​ T4Qs Tons produced ​ 1,034 ​ 905 ​ 907 ​ 954 ​ 3,800 Tons sold ​ 1,355 ​ 995 ​ 854 ​ 934 ​ 4,138 Wash plant recovery in % ​ 64 % 57 % 59 % 63 % ​ Capex (Coal Operations) ​ $ 6,873 ​ $ 6,449 ​ $ 3,792 ​ $ 4,038 ​ $ 21,152 Capex per ton sold (Coal Operations) ​ $ 5.07 ​ $ 6.48 ​ $ 4.44 ​ $ 4.32 ​ $ 5.11 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average cost per ton sold⁽ⁱ⁾ ​ $ 42.74 ​ $ 46.75 ​ $ 50.66 ​ $ 49.77 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ All Mines ​ ​ ​ 3rd 2024 ​ ​ ​ 4th 2024 ​ ​ ​ 1st 2025 ​ ​ ​ 2nd 2025 ​ ​ ​ T4Qs Tons produced ​ 873 ​ 971 ​ 1,020 ​ 1,059 ​ 3,923 Tons sold ​ 926 ​ 875 ​ 1,071 ​ 890 ​ 3,762 Wash plant recovery in % ​ 60 % 62 % 64 % 66 % ​ Capex (Coal Operations) ​ $ 6,810 ​ $ 11,079 ​ $ 6,244 ​ $ 5,793 ​ $ 29,926 Capex per ton sold (Coal Operations) ​ $ 7.35 ​ $ 12.66 ​ $ 5.83 ​ $ 6.51 ​ $ 7.95 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average cost per ton sold⁽ⁱ⁾ ​ $ 52.22 ​ $ 43.25 ​ $ 43.65 ​ $ 46.03 ​ ​ ​ (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. ​ EARNINGS (LOSS) PER SHARE ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 3rd 2025 ​ ​ ​ 4th 2025 ​ ​ ​ 1st 2026 ​ ​ ​ 2nd 2026 Basic ​ $ 0.56 ​ $ (0.01) ​ $ (0.20) ​ $ (0.32) Diluted ​ $ 0.55 ​ $ (0.01) ​ $ (0.20) ​ $ (0.32) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 3rd 2024 ​ ​ ​ 4th 2024 ​ ​ ​ 1st 2025 ​ ​ ​ 2nd 2025 Basic ​ $ 0.04 ​ $ (5.06) ​ $ 0.23 ​ $ 0.19 Diluted ​ $ 0.04 ​ $ (5.06) ​ $ 0.23 ​ $ 0.19 ​ INCOME TAXES Our effective tax rate (“ETR”) is estimated at ~6.4% and ~0% for the six months ended June 30, 2026 and 2025, respectively. For the six months ended June 30, 2026, we estimated our annual ETR based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate. Our ETR differs from the statutory rate due primarily to statutory depletion in excess of tax basis and changes in the valuation allowance. The deduction for statutory percentage depletion does not necessarily change proportionately to changes in income (loss) before income taxes. RESTRICTED STOCK GRANTS See “Item 1. Financial Statements - Note 8 - Stock Compensation Plans” for a discussion of restricted stock unit (“RSUs”). MATERIAL CHANGES IN FINANCIAL CONDITION 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 30 Table of Contents 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 $34.9 million of cash and restricted cash as of June 30, 2026 versus $15.4 million at December 31, 2025. 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 new credit facility. For the details of the borrowing availability under our credit facility, see “Item 1. Financial Statements - Note 4 – Bank Debt” to our unaudited condensed 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 June 30, 2026 unaudited condensed 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. Liquidity consists of our additional borrowing capacity and unrestricted cash and cash equivalents. As of June 30, 2026, we had additional borrowing capacity of $55.3 million under the New Revolving Credit Facility and total liquidity of $84.2 million. Our additional borrowing capacity is net of $19.7 million in outstanding letters of credit as of June 30, 2026 that were required to maintain surety bonds and other credit support obligations. Turbine Equipment Acquisition As of June 30, 2026, we had paid $8.2 million of the purchase price under the APA in the form of payments to third party vendors made on behalf of the Seller, and subsequent to quarter end, through July 31, 2026, we paid an additional $3.0 million to such vendors. The remaining balance of the purchase price of approximately $338.8 million, together with the approximately $100.0 million of expected transportation, refurbishment, insurance, and logistics costs, represents a material cash requirement that significantly exceeds our liquidity of $84.2 million as of June 30, 2026. The timing of the remaining payments will be determined in accordance with the APA, with the substantial majority of the purchase price expected to become payable in connection with delivery of the equipment, currently anticipated in the second half of 2026. We are evaluating financing alternatives to fund the remaining purchase price and related costs, which may include project-level financing, structured financing arrangements supported by our contracted revenue base, proceeds from long-term offtake agreements, borrowings under our New Credit Facility, and issuances of debt or equity securities. There can be no assurance that financing will be available on acceptable terms, or at all. If we are unable to obtain financing on a timely basis, we may seek to renegotiate or extend the payment terms under the APA, which may not be available to us on acceptable terms or at all. If we are unable to renegotiate or extend the payment terms, a failure to make payments when due could result in termination of the APA, the forfeiture of amounts we have already paid, and other damages. In addition, our ability to incur additional indebtedness under our New Credit Facility to fund the remaining purchase price and related costs is subject to compliance with the financial covenants described under “Item 1. Financial Statements - Note 4 – Bank Debt” to our unaudited condensed consolidated financial 31 Table of Contents statements, as amended, and there can be no assurance that we will have sufficient availability under those covenants when needed, or that our lenders would agree to further amend those covenants if required. Consolidated Statement of Cash Flows Summary. The unaudited condensed consolidated statements of cash flows are summarized as follows for the periods presented: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Six Months Ended June 30, ​ ​ ​ ​ ​ 2026 ​ ​ ​ 2025 ​ Change Net cash (used in) provided by operating activities ​ $ (3,394) ​ $ 49,783 ​ $ (53,177) Net cash used in investing activities ​ ​ (33,741) ​ ​ (24,897) ​ ​ (8,844) Net cash (used in) provided by financing activities ​ ​ 56,692 ​ ​ (4,669) ​ ​ 61,361 Increase in cash, cash equivalents, and restricted cash ​ $ 19,557 ​ $ 20,217 ​ $ (660) ​ ​ Operating Activities. The decrease in net cash provided by our operating activities is primarily attributable to the combination of (i) lower Adjusted EBITDA and related working capital items, (ii) increased inventory levels, (iii) lower cash receipts from prepaid forward sales contracts, partially offset by lower cash payments of interest and incremental cash received for annual sales of accredited capacity compared to the first half of 2025. 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 condensed consolidated statements of operations. Investing Activities. The change in net cash used by our investing activities is primarily attributable to (i) an increase in our capital expenditures of $9.2 million attributable to incremental capital expenditure projects of $4.5 million at Merom and an incremental $8.9 million related to the ERAS Project, of which $8.2 million related to payments under the APA, (see “Note 14 – Commitments and Contingencies” ) to the condensed consolidated financial statements, partially offset by lower capitalization of mine development costs at Oaktown and (ii) a $0.3 million decrease in investments in equity method affiliates. ​ For the six months ended June 30, 2026, capital expenditures (“Capex”) was $33.9 million allocated as follows (in millions): ​ ​ ​ ​ Oaktown ​ ​ ​ $ 7.8 Merom ​ 12.6 Merom - ELG ​ 4.6 ERAS Project ​ 8.9 Capex per the condensed consolidated statements of cash flows ​ $ 33.9 We expect our 2026 Capex to remain broadly stable as compared to our 2025 Capex, excluding any impacts of the ERAS Project. The actual amount of our 2026 Capex 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 Capex will not vary materially from our expectations. Financing Activities. The increase in net cash provided by our financing activities is primarily attributable to the net effect of (i) an increase in cash of $53.8 million from the net proceeds of the CMPO, (ii) an increase in net borrowings of bank debt of $14.0 million, (iii) incremental payments of debt issuance costs of $5.9 million, and (iv) a decrease in cash from incremental lease financing payments of $1.2 million. 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. 32 Table of Contents 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 condensed 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. Prior to March 5, 2026, the Company was party to a credit agreement with PNC Bank, National Association (in its capacity as administrative agent, "PNC Bank"). As of December 31, 2025, our bank debt under the PNC Bank credit facility was $30.0 million, which was repaid subsequent to year-end as further described below. 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 daily unused portions of the New Revolving Credit Facility. Following the draw of the Delayed Draw Term Loan in May 2026, the principal balance of the Delayed Draw Term Loan is 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. See “ Item 1. Financial Statements - Note 4 – Bank Debt ” to our unaudited condensed 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 $18.3 million, including $6.5 million at Merom, presented as asset retirement obligations (“ARO”) 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 $30.9 million to cover ARO. CRITICAL ACCOUNTING ESTIMATES For a description of our critical accounting policies and estimates, refer to “ Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations ” included in our 2025 Form 10-K. We did not have any material changes in critical accounting policies, estimates, judgments and assumptions during the three and six months ended June 30, 2026.