Hallador Energy HNRG Form 10-Q filing Q2 FY2026

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PART I - FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS (Unaudited)

ITEM 1. FINANCIAL STATEMENTS

See accompanying notes to the condensed consolidated financial statements.

Hallador Energy Company

Condensed Consolidated Statements of Operations

(in thousands, except per share data)

(unaudited)

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See accompanying notes to the condensed consolidated financial statements.

Hallador Energy Company

Condensed Consolidated Statements of Cash Flows

(in thousands)

(unaudited)

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See accompanying notes to the condensed consolidated financial statements.

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See accompanying notes to the condensed consolidated financial statements.

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Hallador Energy Company

Notes to Condensed Consolidated Financial Statements

(unaudited)

(1) BASIS OF PRESENTATION

Organization

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Hallador Energy Company (“Hallador” or the “Company”) 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 electricity to coal. The Company’s condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). The condensed consolidated financial statements include the accounts of Hallador and our wholly owned subsidiaries, including our main operating subsidiaries, Hallador Power Company, LLC (“Hallador Power”) and Sunrise Coal, LLC (“Sunrise”) and their respective subsidiaries, as well as Hourglass Sands, LLC. Additionally, we hold 50% interests in Sunrise Energy, LLC (“Sunrise Energy”), a private gas exploration company with operations in Indiana and Oaktown Gas, LLC (“Oaktown Gas”), which we account for using the equity method. Our operations include Hallador Power which provides accredited capacity and energy to utilities and other energy market participants through the MISO interconnection, and Sunrise which mines bituminous coal in Indiana to serve various power plants in the Midwest and Southeast United States.

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Reclassifications

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It was determined that electric sales and utilities expenses were each understated by $2.7 million in the unaudited condensed consolidated statements of operations for the three months ended March 31, 2026. The understatements had no impact on net loss for the period. These amounts have been properly reflected in our unaudited condensed consolidated statements of operations for the six months ended June 30, 2026 and are excluded from the accompanying condensed consolidated statements of operations for the three months ended June 30, 2026. As the impacts are not considered material to the previously reported amounts, they will be corrected when we present the three months ended March 31, 2026 in our March 31, 2027 Quarterly Report on Form 10-Q. This correction did not impact previously reported amounts of assets, liabilities, equity, net loss, or cash flows.

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Certain other reclassifications have been made to the Company’s prior period condensed consolidated financial information to conform to the current period presentation. These presentation changes did not impact the Company’s condensed consolidated net loss, consolidated cash flows, total assets, total liabilities or total stockholders’ equity.

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Basis of Presentation

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Our unaudited condensed consolidated financial statements have been prepared in accordance with GAAP and with the instructions to Form 10-Q and Article 10 of Regulation S-X for interim financial information. Accordingly, these financial statements do not include all of the information required by GAAP or Securities and Exchange Commission (“SEC”) rules and regulations for complete financial statements. In the opinion of management, these financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results of operations for the interim periods presented. The results of operations for any interim period are not necessarily indicative of results for the full year. These unaudited condensed consolidated financial statements should be read in conjunction with our 2025 consolidated financial statements and notes thereto included in our 2025 Annual Report on Form 10-K (our “2025 10-K”). All significant intercompany accounts and transactions have been eliminated.

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Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Estimates and assumptions are used in accounting for, among other things, deferred income tax accounts, coal reserves, depreciation, depletion, and

amortization, impairment analyses, and calculation of asset retirement obligations (“ARO”). Actual results could differ from those estimates.

Change in Accounting Estimate

On May 1, 2026, the Company entered into a 12-year capacity agreement with a subsidiary of a utility for planning years 2028 through 2040, as previously reported on the Company's Current Report on Form 8-K filed May 6, 2026. As a result of this agreement, together with the Company's other long-term contracted commitments and future maintenance plans, the Company reevaluated the estimated remaining useful life of the Merom Generating Station and determined that the plant's estimated operating life should also be extended through 2040, compared to the previous estimate of 2032. Accordingly, effective June 1, 2026, the Company extended the estimated useful lives of the plant and related assets to align with the revised remaining life of the facility. This change was accounted for prospectively as a change in accounting estimate; depreciation expense recorded in prior periods was not adjusted, and the remaining net book value of the affected assets is being depreciated over the revised remaining useful lives. The effect of this change for both the three and six months ended June 30, 2026 was a decrease in depreciation expense of $1.2 million and a decrease in net loss of $1.2 million, or approximately $0.03 per basic and diluted share, which impacted our Electric Operations segment.

(2) RECENT ACCOUNTING PRONOUNCEMENTS

Recent Accounting Pronouncements – Not Yet Adopted

In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting-Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses (“ASU 2024-03”). The update is intended to improve the disclosures about a public business entity’s expenses by requiring more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation and amortization) included within income statement expense captions. The guidance will be effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. The Company is currently evaluating the impact of adoption of the standard on its financial statement disclosures.

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(3) INVENTORY

Inventory is valued at the lower of cost or net realizable value (“NRV”). Coal inventory includes NRV adjustments of $0.1 million as of June 30, 2026, and December 31, 2025. During 2025, as part of the Company’s routine inventory reconciliation process, a downward adjustment of $2.6 million was recorded to coal inventory.

(4) BANK DEBT

New Credit Facility

On March 5, 2026, Hallador entered into a credit agreement with Texas Capital Bank, as administrative agent, and Old National Bank, among others, that replaces the Credit Agreement with PNC Bank, National Association, (“PNC”) and includes a $75.0 million senior secured revolving credit facility (the "New Revolving Credit Facility") and a $45.0 million senior secured term loan facility (the "Delayed Draw Term Loan", and together with the New Revolving Credit Facility, the "New Credit Facility"). The New Revolving Credit Facility includes (i) a $25.0 million sub-facility for letters of credit and (ii) a $10.0 million sub-facility for swingline loans. The Company may, subject to conditions set forth in the New Credit Facility, request additional revolving facility commitments and incremental term loan commitments in an aggregate amount not to exceed $25.0 million. The Company and certain of its subsidiaries, as guarantors under the New Credit Facility, granted a security interest in substantially all of their assets to secure the Company’s obligations under the New Credit Facility.

The New Credit Facility bears interest at a rate equal to, at the Company’s election, either a base rate or term secured overnight financing rate (“SOFR”), plus an applicable margin based upon the Company’s total leverage ratio. Under the

New Credit Facility, (A) base rate loans will bear interest at a rate equal to the greater of (i) the prime rate, (ii) the sum of the Federal Funds Rate plus one half of one percent (0.50%), and (iii) the term SOFR plus one percent (1.00%), in each case, plus the applicable margin for base rate loans, which ranges from 2.25% to 2.75%, and (B) term SOFR loans will bear interest at term SOFR, plus the applicable margin for term SOFR loans, which ranges from 3.25% to 3.75%. The New Credit Facility includes a commitment fee of 0.50% on the daily unused portions of the New Revolving Credit Facility. As of June 30, 2026, we were subject to paying the applicable SOFR plus 3.50% on outstanding bank debt, which equates to an all-in rate of 7.11%.

On May 15, 2026, the Company borrowed the $45.0 million available under the Delayed Draw Term Loan. A portion of the proceeds was used to repay $8.0 million of outstanding borrowings under the New Revolving Credit Facility, with the remainder available for ongoing working capital and general corporate purposes. The principal balance of the Delayed Draw Term Loan is due and payable in quarterly installments of 2.5% of the original principal amount, or $1.1 million, commencing September 30, 2026, with a final payment of the remaining balance upon maturity on March 5, 2029.

On April 21, 2026, the Company entered into a First Amendment to the Credit Agreement, which among other things made certain administrative and technical modifications. On June 25, 2026, the Company entered into a Second Amendment to the Credit Agreement (the "Second Amendment"), which modified certain financial covenants. The maximum Total Leverage Ratio was amended to 4.25 to 1.0 for periods ending on or after June 30, 2026, compared to our original 4.0 to 1.0. The maximum Senior Secured Leverage Ratio was amended to 3.00 to 1.0 for periods ending June 30, 2026 through September 30, 2026, and 2.75 to 1.0 for periods ending December 31, 2026 through March 31, 2027, returning to 2.50 to 1.0 for periods ending on or after June 30, 2027. The Second Amendment also updated certain schedules to the Credit Agreement to reflect recently executed material agreements, including the Asset Purchase Agreement with Energy World Corporation Ltd. The increase in our maximum permitted Total Leverage Ratio and Senior Secured Leverage Ratio under the Second Amendment was obtained, in part, to provide us with additional flexibility in connection with our anticipated financing of the turbine equipment acquisition described in “Note 14 – Commitments and Contingencies” to the condensed consolidated financial statements. Our ability to fund the remaining purchase price and related costs, including through additional borrowings under the New Credit Facility, remains subject to compliance with these covenants, as amended, and there can be no assurance that our current covenant levels will provide sufficient capacity for that purpose or that additional covenant relief will be available if needed.

Prior Credit Agreement

The Company was party to a credit agreement with PNC, in its capacity as administrative agent, which consisted of a revolving credit facility of up to $75.0 million and a term loan.

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 operating flexibility for the remainder of 2025 by redefining covenants and deferring certain covenants until the third quarter of 2025. During the second quarter of 2025, the Company entered into a $35.0 million prepaid forward power sales contract of which $19.0 million of the proceeds were deposited into a money market account with the administrative agent as a compensating balance. The compensating balance was utilized to fully repay the outstanding term loan during the fourth quarter of 2025. As of March 5, 2026, the Company fully repaid its revolving credit facility with PNC.

Liquidity

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.

Fees

Bank fees and other costs incurred in connection with the New Credit Facility totaled $6.2 million and are amortized over the term of the New Credit Facility. Upon the funding of the Delayed Draw Term Loan on May 15, 2026, unamortized fees allocated to the Delayed Draw Term Loan were reclassified from other assets to a direct deduction from the carrying amount of the Delayed Draw Term Loan. Unamortized bank fees as of June 30, 2026, and December 31, 2025, were $5.6 million and $0.3 million, respectively, of which $3.5 million related to the New Revolving Credit Facility and is included in other noncurrent assets, and $2.1 million related to the Delayed Draw Term Loan and is presented as a reduction of bank debt in the table below. The New Credit Facility includes a commitment fee of 0.50% on any daily unused portions of the New Revolving Credit Facility.

Unamortized bank fees and other costs incurred in connection with our Prior Credit Agreement of $0.2 million were recorded as a loss on extinguishment of debt on the condensed consolidated statements of operations.

Bank debt, less debt issuance costs, is presented below (in thousands):

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(1) Unamortized debt issuance costs related to the New Revolving Credit Facility of $3.5 million are included in other noncurrent assets on the condensed consolidated balance sheets as of June 30, 2026.

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Future maturities of bank debt as of June 30, 2026, are as follows (in thousands):

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Covenants

As of June 30, 2026 our covenants include:

• Total leverage ratio – 4.25 to 1.00
• Senior secured leverage ratio – 3.00 to 1.00 stepping down to 2.75 to 1.00 in the fourth quarter of 2026, and 2.50 to 1.00 in the second quarter of 2027.
• Fixed charge coverage ratio – 1.25 to 1.00.

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As of June 30, 2026, we were in compliance with all covenants defined in the New Credit Facility.

Interest Rate

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%, as further described above. The applicable margin is determined based upon the Company's leverage ratio and the type of loan drawn. As of June 30, 2026, we were subject to paying the applicable SOFR plus 3.50% on any outstanding bank debt which equates to an all-in rate of 7.11%.

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(5) ACCRUED LIABILITIES AND OTHER

Accrued liabilities and other consist of the following for the indicated dates (in thousands):

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(6) REVENUE

Revenue from Contracts with Customers

We account for contracts with customers when the parties have executed the contract and are committed to performing their respective obligations, the rights of each party are identified, payment terms are identified, the contract has commercial substance, and it is probable substantially all the consideration will be collected. We recognize revenue when we satisfy a performance obligation by transferring control of a good or service to a customer.

Electric Operations

We concluded that for a Power Purchase Agreement (“PPA”) that is not determined to be a lease or derivative, the definition of a contract and the criteria in ASC 606, Revenue from Contracts with Customers (“ASC 606”), are met at the time a PPA is executed by the parties, as this is the point at which enforceable rights and obligations are established. Accordingly, we concluded that a PPA that is not determined to be a lease or derivative constitutes a valid contract under ASC 606.

Under accredited capacity PPAs, we recognize revenue daily, based on an output method of capacity made available as part of any stand-ready obligations for contracted accredited capacity performance obligations.

For delivered energy PPAs, we recognize revenue daily for the actual delivered MWh of electricity. For the prepaid delivered energy PPAs, we recognize revenue daily for the funds received for the actual delivered MWh of electricity plus any accretion attributable to the time value of money.

When 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 in our condensed consolidated statements of operations.

Coal operations

Our coal revenue is derived from sales to customers of coal produced at our mining facilities. Our customers typically purchase coal free on board from our mine sites where title, risk of loss, and control pass to the customer. Our customers arrange for and bear the costs of transporting their coal from our mines to their plants or other specified discharge points. Our customers are typically domestic utility companies. Coal sales agreements with our customers are fixed-priced, fixed-volume supply contracts, but some include a pre-determined escalation in price for each year and some allow for our customers to vary the fixed-volume by pre-determined quantities during a set period, such as quarterly. The terms of our coal sales agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary by customer.

Coal sales agreements typically contain coal quality specifications which require the raw coal sold by us to the customer to be (i) substantially free of magnetic material and other foreign material impurities and (ii) crushed to a maximum size as set forth in the respective coal sales agreement. Price adjustments are made and billed in the month the coal sale was recognized based on quality standards that are specified in the coal sales agreement, such as British thermal unit factor, moisture, ash, and sulfur content, and can result in either increases or decreases in the value of the coal shipped. When applicable, we have constrained the expected value of variable consideration in our estimation of transaction price and only included this consideration to the extent that it is probable that a significant revenue reversal will not occur.

Disaggregation of Revenue

Revenue is disaggregated by revenue source for our Electric Operations and by primary geographic markets for our Coal Operations, as we believe this best depicts how the nature, amount, timing, and uncertainty of our revenue and cash flows are affected by economic factors.

Electric Operations

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Coal Operations

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Performance Obligations

A performance obligation is a promise in a contract with a customer to provide distinct goods or services. Performance obligations are the unit of account for purposes of applying the revenue recognition standard and therefore determine when and how revenue is recognized.

Electric Operations

We concluded that each MWh of delivered energy is capable of being distinct as a customer could benefit from each on its own by using/consuming it as a part of its operations. We also concluded that the stand-ready obligation to be available to provide electricity is capable of being distinct as each unit of accredited capacity provides an economic benefit to the holder and could be sold by the customer.

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Coal Operations

In most of our coal contracts, the customer contracts with us to provide coal that meets certain quality criteria. We consider each ton of coal a separate performance obligation and allocate the transaction price using the base price per the contract, increased or decreased for quality adjustments.

The following table illustrates the balance of all current Electric and Coal Operations contracts allocated to performance obligations that are unsatisfied or partially unsatisfied as of June 30, 2026 and disaggregated by segment and contract duration (in thousands).

(1) Certain contracted forward sales positions included above are subject to approval by the Indiana Utility Regulatory Commission.

(2) Coal Operations revenue consists of consolidated revenue excluding our intercompany revenues from Merom.

Contract Balances

Under ASC 606, the timing of when a performance obligation is satisfied can affect the presentation of accounts receivable, contract assets and contract liabilities. The main distinction between accounts receivable and contract assets is whether consideration is conditional on something other than the passage of time. A receivable is an entity’s right to consideration that is unconditional.

Under the typical payment terms of our contracts with customers, the customer pays us the contracted price for electricity or accredited capacity. For coal contracts, the customer pays us a base price for the coal, increased or decreased for any quality adjustments. Amounts billed and due are recorded as trade accounts receivable and included in accounts receivable in our condensed consolidated balance sheets. Payments received prior to fulfilling our performance obligations are included in contract liabilities in our condensed consolidated balance sheets. When the Company receives customer payments more than one year in advance of the related performance obligations and the financing is significant in the context of the contract, the Company adjusts the transaction price for the significant financing component associated with these contracts at risk adjusted market rates. The resulting interest accretion is recognized as interest expense over the period between the customer payment date and the expected satisfaction of the performance obligation.

The following table shows our beginning and ending accounts receivable balances from contracts with customers for the periods presented (in thousands):

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As the Company fulfills its contractual obligations, we recognized those amounts in revenue. The following table reconciles our beginning and ending contract liabilities for the periods presented (in thousands):

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(7) INCOME TAXES

For the six months ended June 30, 2026 and 2025, we recorded income taxes using an estimated annual effective tax rate based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate. The effective tax rate for the six months ended June 30, 2026 and 2025, was approximately 6.4% and 0%, respectively. Historically, our actual effective tax rates differed from the statutory effective rate primarily due to the benefit received from statutory percentage depletion in excess of tax basis. The deduction for statutory percentage depletion does not necessarily change proportionately to changes in income (loss) before income taxes.

On July 4, 2025, H.R.1, commonly referred to as the One Big Beautiful Bill Act (“OBBBA”) was enacted. The OBBBA includes a broad range of tax reform provisions affecting businesses, including extending and modifying certain key Tax Cuts & Jobs Act provisions (both domestic and international), expanding certain Inflation Reduction Act incentives, and accelerating the phase-out of or repealing others. We have analyzed the provisions within the act and determined that the benefits relating to capital expenditures and deductibility of interest under IRC Section 163(j) will provide cash flow benefits to the company by accelerating deductions for tax purposes. As the material benefits relate to the timing of deductions, there were no material impact affecting the effective tax rate or the valuation allowance determination in the period that OBBBA was enacted.

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(8) STOCK COMPENSATION PLANS

Non-vested grants and activity for the period presented are as follows (in whole shares):

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For the three and six months ended June 30, 2026, our stock compensation expense was $1.4 million and $2.5 million, respectively. For the three and six months ended June 30, 2025, our stock compensation expense was $0.5 million and $1.6 million, respectively.

Non-vested restricted stock unit (“RSU”) grants will vest as follows (in whole shares):

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As of June 30, 2026, unrecognized stock compensation expense to be recognized over the respective vesting period is $6.9 million, and we had 1,780,478 RSUs available for future issuance. RSUs are not allocated earnings and losses as they are considered non-participating securities. Forfeitures are recognized as they occur.

(9) SELF-INSURANCE

The Company is self-insured for certain risks, including physical damage and operational liability, related to our non-leased underground mining equipment. The Company records a liability for self-insured risks when a loss is both probable and reasonably estimable. The Company had no accrual for self-insurance liabilities as of June 30, 2026 or December 31, 2025.

The Company also self-insures for a portion of its workers’ compensation claims under a guaranteed cost program. Under this program, the Company is responsible for the first $1.0 million per claim up to an aggregate of $4.0 million annually. As of June 30, 2026 and December 31, 2025, the Company has restricted cash of $4.0 million and $3.0 million, respectively, for future workers’ compensation claim payments. The Company had $5.4 million and $5.2 million of workers’ compensation reserve as of June 30, 2026 and December 31, 2025, respectively, in accrued liabilities on the condensed consolidated balance sheets.

(10) FAIR VALUE MEASUREMENTS

We account for certain assets and liabilities at fair value. The hierarchy below lists three levels of fair value based on the extent to which inputs used in measuring fair value are observable in the market. We categorize each of our fair value measurements in one of these three levels based on the lowest level input that is significant to the fair value measurement in its entirety. These levels are:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. We have no Level 1 instruments.

Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). ARO liabilities use Level 3 non-recurring fair value measures*.*

The carrying amounts for cash equivalents, accounts receivable, accounts payable, accrued liabilities and other, approximate fair value due to the short maturity of those instruments. Our debt is recorded at amortized cost, which approximates fair value due to the variable interest rates in the agreement and is collateralized primarily by our assets.

Credit Risk

The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, and restricted cash.

The Company’s cash and cash equivalent and restricted cash balances on deposit with financial institutions totaled $34.9 million and $15.4 million as of June 30, 2026 and December 31, 2025, respectively, which exceeded FDIC insured limits. The Company regularly monitors these institutions’ financial condition. The Company utilizes large and reputable banking institutions which it believes mitigates these risks. The Company has not experienced any losses in such accounts.

(11) EQUITY METHOD INVESTMENTS

We own a 50% interest in Sunrise Energy which owns gas reserves and gathering equipment with plans to develop and operate such reserves. Sunrise Energy also plans to develop and explore for oil, natural gas, and coal-bed methane gas reserves on or near our underground coal reserves. The carrying value of the investment included in our condensed consolidated balance sheets was $1.7 million and $1.9 million as of June 30, 2026 and December 31, 2025, respectively.

The Company also owns a 50% interest in Oaktown Gas, LLC. Oaktown Gas, LLC operates an emission abatement project through the destruction of gases extracted from the Oaktown mines to generate carbon credits and other emissions offset credits. The carrying value of the investment included in the condensed consolidated balance sheets as of June 30, 2026 and December 31, 2025, was $0.6 million and $0.7 million, respectively.

(12) SEGMENTS OF BUSINESS

Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The 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.

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Our Electric Operations segment includes the electric power generation facilities of our Merom power plant, which is a two-unit, 1,080-megawatt rated coal fired power plant located in Sullivan County, Indiana. Our sales region is in MISO Zone 6, which includes Indiana and a portion of western Kentucky. Revenues from our Electric Operations segment consist primarily of delivered energy and accredited capacity revenues. Fuel costs included in our Electric Operations segment include the cost of coal purchased from our Coal Operations segment, which are based on multi-year contracts which approximate market prices at the time the contracts were agreed.

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Our Coal Operations segment includes the Oaktown 1 underground mining complex, as well as other currently idled mining facilities, which produce high-quality bituminous coal from the Illinois Basin. Revenue from our Coal Operations segment consists of sales of coal to various third parties and to Merom. Coal sales to our Electric Operations are based on multi-year contracts that approximated market prices at the time the contracts were agreed. Intercompany coal sales and amounts above actual costs to produce the coal are eliminated in the condensed consolidated statements of operations.

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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 equity method investments.

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The CODM evaluates segment performance based upon Segment EBITDA for each business segment. Segment EBITDA is calculated for each segment as follows:

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1. For our Electric Operations segment, Segment EBITDA is comprised of accredited capacity and delivered energy revenues less certain significant segment expenses, which include (i) variable costs comprised of fuel costs and certain other operating costs, such as limestone and soda ash, (ii) other operating and maintenance costs, (iii) costs of purchased power, (iv) utilities, (v) labor and (vi) general and administrative costs.

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2. For our Coal Operations segment, Segment EBITDA is comprised of coal sales less certain significant segment expenses, which include (i) fuel, (ii) other operating and maintenance costs, (iii) utilities, (iv) labor and (v) general and administrative costs.

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Segment EBITDA for each segment is a key measure used by our CODM and provides information about our core operating performance, significant expenses and ability to generate cash flow. Additionally, Segment EBITDA provides investors with the financial analytical framework upon which our CODM bases financial, operational, compensation and planning decisions and presents a measurement that investors, rating agencies and debt holders have indicated is useful in assessing us and our results of operations. Our CODM reviews variable costs, as defined above, in our Electric Operations segment in order to evaluate the efficiency of that segment’s operations.

Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the three months ended June 30, 2026 and 2025 (in thousands):

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Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the six months ended June 30, 2026 and 2025 (in thousands):

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(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. ​

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Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the three months ended June 30, 2026 (in thousands):

Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the three months ended June 30, 2025 (in thousands):

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Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the six months ended June 30, 2026 (in thousands):

Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the six months ended June 30, 2025 (in thousands):

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Presented below is the summary of Segment EBITDA (in thousands):

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Presented below is our reconciliation of Segment EBITDA to the most comparable GAAP account, income (loss) before income taxes (in thousands):

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Presented below are our Electric and Coal Operations assets and capital expenditures for the periods presented below (in thousands):

(1) Coal Operations assets include cash held on behalf of the consolidated group. Cash held by our Coal Operations includes funds transferred from Electric Operations and Hallador for centralized treasury management purposes. This presentation is not reflective of Coal Operations earnings capacity; refer to the condensed consolidated balance sheets and the “Liquidity of Hallador” in the “Material Changes in Financial Condition” section of “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a complete view of the Company's cash position.

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Cash and cash equivalents included in Coal Operations assets were $28.1 million and $9.4 million as of June 30, 2026 and December 31, 2025, respectively.

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(13) NET INCOME (LOSS) PER SHARE

The following table (in thousands, except per share amounts) sets forth the computation of basic earnings (loss) per share for the periods presented:

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The following table (in thousands, except per share amounts) sets forth the computation of diluted net income (loss) per share:

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The computation of diluted net loss per share for the three and six months ended June 30, 2026 excludes 304,598 and 284,662, respectively, potentially dilutive securities related to unvested restricted stock units as their inclusion would have been anti-dilutive.

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(14) COMMITMENTS AND CONTINGENCIES

Commitments

Asset Purchase Agreement — Turbine Equipment

On May 30, 2026, the Company entered into an Asset Purchase Agreement (the "APA") with Energy World Corporation Ltd. (the “Seller”) 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. The Company expects to incur approximately $100.0 million of additional costs for transportation, refurbishment, insurance, and logistics in connection with the delivery of the equipment.

Subsequent to quarter end, the Company and the Seller agreed to extend the deadline for loading the equipment for transport to the U.S. and to adjust the timing of certain payments to third party vendors to be made on behalf of the Seller.

The Company paid $8.2 million to third party vendors on behalf of the Seller during the six months ended June 30, 2026 which is included in construction work in progress on the condensed consolidated balance sheets. An additional $3.0 million was paid to these vendors through July 31, 2026.

Contingencies

Our Coal Operations subsidiary was party to litigation in which the plaintiffs alleged violations of the Fair Labor Standards Act and state law due to alleged failure to compensate for time "donning" and "doffing" equipment and to account for certain bonuses in the calculation of overtime rates and pay. In January 2025, we agreed to settle with the plaintiffs such litigation for $2.8 million, which was recorded in operating expenses on our consolidated statements of operations for the year ended December 31, 2024. During the third quarter of 2025, we transferred $2.7 million into an escrow account and in late 2025 the settlement terms were approved by the court. At June 30, 2026, there were no further amounts accrued on our consolidated balance sheet related to this litigation.

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(15) AT MARKET AGREEMENT (“ATM”) AND CONFIDENTIALLY MARKETED PUBLIC OFFERING (“CMPO”)

ATM

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On December 18, 2023, we entered into an At Market Issuance Sales Agreement (the “Sales Agreement”) with B. Riley Securities, Inc. (the “Agent”), pursuant to which we could issue and sell, from time to time, shares (the “Shares”) of our common stock, par value $0.01 per share (the “Common Stock”), with aggregate gross proceeds of up to $50.0 million through an “at-the-market” equity offering program under which the Agent will act as sales agent (the “ATM Program”). Under the Sales Agreement, we or the Agent had the right, by giving five days’ notice, to terminate the Sales Agreement in our and the Agent’s sole discretion. On December 16, 2025, the Company increased the aggregate gross sales proceeds under the ATM Program from $50.0 million to $100.0 million by amending the Sales Agreement.

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During the first quarter of 2026, we issued 10,832 shares of Common Stock under the ATM Program for net proceeds of $0.2 million. During the year ended December 31, 2025, we issued 697,227 shares of Common Stock under the ATM Program for net proceeds of $13.5 million. In January 2026, the Company delivered written notice to the Agent to terminate the Sales Agreement effective January 18, 2026. As a result of the termination of the Sales Agreement, the Company will not offer or sell any further shares under the ATM Program.

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CMPO

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In January 2026, the Company conducted a confidentially marketed public offering (the "CMPO") pursuant to a base prospectus and a final prospectus supplement that were filed with the SEC. The Company sold a total of 3,194,444 shares of common stock, at a price to the public of $18.00 per share for aggregate gross proceeds of approximately $57.5 million, including the exercise of the underwriter’s option prior to deducting underwriting discounts, commissions, and other offering expenses of $3.7 million.

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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:

• 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.

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.

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.

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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 ***

• 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.

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

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• (in thousands)
• (per MWh)
• (per MWh)_

(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.

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Q2 2026 vs. Q2 2025

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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. When 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.

YTD 2026 vs. YTD 2025

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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. When 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.

Coal Operations

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• (in thousands)
• (per ton)
• (per ton)_

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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,

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.

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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.

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Quarterly coal sales and cost data on a segment basis are as follows (in thousands, except per ton data and wash plant recovery percentage):

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(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.

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EARNINGS (LOSS) PER SHARE

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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

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

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:

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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.

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For the six months ended June 30, 2026, capital expenditures (“Capex”) was $33.9 million allocated as follows (in millions):

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.

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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's power generation and mining activities, or with existing or forecasted financial or commodity transactions. The types of market risks that Hallador is exposed to are commodity price risk, interest rate risk, inflation risk, and counterparty credit risk.

Commodity Price Risk

Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities, and correlations between various commodities, such as natural gas, electricity, coal, oil, and emissions credits. We manage the commodity price risk of the Company's generation and mining operations by entering into various instruments to manage the variability in future cash flows from forecasted sales and purchases of power and fuel. These instruments include prepaid forward contracts, PPAs, and other bilateral agreements. Hallador uses these agreements to manage and

fix the prices of certain purchases and sales to alleviate market risk and improve visibility into future results. See the “Forward Sales Position” table within the “Material Changes in Results of Operations” section of “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

We are exposed to market price fluctuations for emission credits related to our investments in Sunrise Energy and Oaktown Gas, which had an aggregate carrying value of $2.3 million at June 30, 2026. For additional information regarding our investments in Sunrise Energy and Oaktown Gas, see “Item 1. Financial Statements - Note 11. – Equity Method Investments” to our condensed consolidated financial statements.

Interest Rate Risk

We are exposed to changes in interest rates primarily as a result of our borrowing activities, which include instruments with variable rates. Our primary exposure to variable rates is through our SOFR-indexed credit facilities.

In general, we monitor the interest rate market and determine whether to enter into instruments to protect against increases in the interest rates on our variable-rate debt. From time to time, we may use interest rate swaps, interest rate cap, floor or collar agreements that lock in a maximum interest rate if variable rates rise, but also may allow our company to benefit, to a limited extent in the case of collars, from declines in market rates. We use judgment to determine the appropriate composition of interest rate derivative instruments, taking into account the relative costs and benefits in light of current and expected future market conditions, liquidity issues and other factors. As of June 30, 2026 and December 31, 2025, we did not hold any interest rate derivative instruments.

Weighted Average Variable Interest Rate. At June 30, 2026 and December 31, 2025, the outstanding principal amount of our variable-rate indebtedness aggregated $45.0 million and $30.0 million, respectively, and the weighted average interest rate (including margin) on such variable-rate indebtedness was approximately 7.11% and 8.17%, respectively, excluding the effects of interest rate derivative contracts, deferred financing costs, original issue premiums or discounts and commitment fees, all of which affect our overall cost of borrowing. A 100 basis point increase in SOFR would increase annual interest expense by approximately $0.5 million.

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Inflation Risk

We are subject to inflationary pressures with respect to labor, procurement of electrical and mining equipment, and other costs. While we attempt to increase our revenue to offset increases in costs, there is no assurance that we will be able to do so. Therefore, costs could rise faster than associated revenue, thereby resulting in a negative impact on our operating results, cash flows and liquidity. The economic environment in which we operate is a function of government, economic, fiscal and monetary policies and various other factors beyond our control that could lead to inflation. We are unable to predict the extent that price levels might be impacted in future periods in the markets in which we operate.

Counterparty Credit Risk

We are exposed to the risk that the counterparties to our undrawn debt facilities and cash investments will default on their obligations to us. We manage these credit risks through the evaluation and monitoring of the creditworthiness of, and concentration of risk with, the respective counterparties. In this regard, credit risk associated with our undrawn debt facilities is spread across multiple counterparties, however notwithstanding, the default of certain counterparties could have a significant impact on our business. Most of our cash currently is invested in either (i) money market funds, including funds that invest in high-quality short-term instruments that preserve principal and offer daily liquidity, or (ii) overnight deposits with banks that transfer balances nightly into repurchase agreements collateralized by high-quality securities, including US government instruments. To date, neither the access to nor the value of our cash and cash equivalent balances have been adversely impacted by liquidity problems of financial institutions.

We are also exposed to counterparty performance risk under the APA. Our ability to receive the turbine equipment we agreed to purchase, and to recover amounts we paid toward the purchase price, depends on the performance of the Seller and its designated vendors.

We invest our cash with financial institutions that meet high credit quality standards. We are exposed to the credit risk of these financial institutions and to interest rate risk in relation to the interest earning potential of our cash and cash equivalent balances. In order to mitigate these risks, we actively manage the deposits of our cash balances in light of our and our subsidiaries’ forecasted liquidity requirements.

At June 30, 2026 and December 31, 2025, our exposure to counterparty credit risk included (i) cash and cash equivalents and restricted cash of $34.9 million and $15.4 million, respectively, and (ii) aggregate availability of undrawn debt facilities of $55.3 million and $28.8 million, respectively.

While we currently have no specific concerns about the creditworthiness of any counterparty for which we have material credit risk exposures, we cannot rule out the possibility that one or more of our counterparties could fail or otherwise be unable to meet its obligations to us. Any such instance could have an adverse effect on our cash flows, results of operations, financial condition and/or liquidity.

Although we actively monitor the creditworthiness of our key vendors, the financial failure of a key vendor could disrupt our operations and have an adverse impact on our revenue and cash flows.

ITEM 4. CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS

We maintain a system of disclosure controls and procedures that are designed for the purpose of ensuring that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our CEO and CFO as appropriate to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our CEO and CFO of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective for the purposes discussed above.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes to our internal control over financial reporting during the quarter ended June 30, 2026, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Item 1. Financial Statements - Note 14. – “Contingencies” to our condensed consolidated financial statements. Except as described therein, the Company is not currently a party to any legal proceedings that management believes, either individually or in the aggregate, would reasonably be expected to have a material adverse effect on the Company’s business, results of operations, financial condition, or liquidity.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors disclosed in Part I, Item 1A, "Risk Factors" in our Annual Report on Form 10-K for the fiscal year ended December 31, 2025, filed with the SEC on March 12, 2026, except as set forth below.

We entered into a substantial commitment to acquire turbine equipment for which we have not yet secured financing, and our failure to timely obtain financing or perform our obligations under the related agreements could have a material adverse effect on our business, financial condition, and results of operations.

On May 30, 2026, we entered into an Asset Purchase Agreement (the “APA”) with Energy World Corporation Ltd. (the “Seller”) 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, plus approximately $100.0 million of additional costs we expect to incur for transportation, refurbishment, insurance, and logistics. As of June 30, 2026, we paid $8.2 million of the purchase price, and we paid an additional $3.0 million subsequent to quarter end. The remaining balance of approximately $338.8 million is expected to become payable in accordance with the APA, with the substantial majority due in connection with delivery of the equipment, which is currently anticipated in the second half of 2026.

This remaining commitment significantly exceeds our total liquidity of $84.2 million as of June 30, 2026. We are evaluating financing alternatives, 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. We have not secured commitments for this financing, and there can be no assurance that financing will be available to us on acceptable terms, or at all. If we are unable to obtain sufficient financing on a timely basis, we may be unable to satisfy our payment obligations under the APA, which could result in a breach or default under that agreement, forfeiture of amounts we have already paid, termination of the APA, litigation, and other damages, any of which could have a material adverse effect on our business, financial condition, cash flows, and results of operations.

The turbine equipment we are acquiring is intended to support our proposed expansion of generation capacity through MISO’s ERAS program. Our ability to complete that expansion and to realize the anticipated benefits of the equipment is subject to MISO’s approval of our ERAS application and other construction, permitting, financing, and regulatory contingencies, many of which are outside our control and have not yet been satisfied. If we do not obtain the necessary approvals, or if the expansion project does not otherwise proceed, we may be unable to deploy the equipment as planned, and our alternatives may be limited to selling the project together with the equipment or selling the equipment on a standalone basis, potentially at a loss and on terms less favorable than we currently anticipate.

The turbine equipment must be transported internationally and domestically through a complex, multi-stage logistics process, and delays, damage, or cost overruns in that process could adversely affect the cost, timing, and expected benefits of our planned expansion.

The turbine equipment we are acquiring under the APA is currently located outside the United States and must be transported through a complex, multi-stage logistics process before it can be placed into service, including disassembly and packaging, international ocean shipment to the United States, customs and import clearance, and overland transport to a Siemens facility for inspection and refurbishment, followed by transport to the site of our planned expansion at our Merom Generating Station in Sullivan County, Indiana. The equipment consists of large, heavy, and specialized components that require heavy-lift vessels, specialized rigging and transport equipment, and oversize and overweight load permits, and we will rely on the Seller, its designated vendors, Siemens, and other third-party carriers and logistics providers, whose performance is largely outside our control.

This process is subject to numerous risks, including damage to or loss of the equipment in transit; limited availability of qualified vessels, carriers, and equipment; port congestion and labor disruptions; adverse weather; delays in obtaining export licenses, import clearances, and transport permits; geopolitical events and disruptions to shipping lanes; and the imposition of, or changes in, tariffs, duties, and other trade measures applicable to imports into the United States. The equipment includes long-lead-time components that would be difficult, time-consuming, and costly to repair or replace if damaged or lost in transit. Any insurance we maintain on the equipment during transport may not be sufficient to cover all losses and would not compensate us for delays to our planned expansion.

Our estimate of approximately $100.0 million of transportation, refurbishment, insurance, and logistics costs is based on assumptions regarding, among other things, shipping costs, carrier and equipment availability, tariff and duty rates, permitting timelines, and the scope of refurbishment work required, any of which may prove inaccurate, and actual costs could materially exceed that estimate, increasing the amount of financing we require. In addition, because the substantial majority of the purchase price under the APA becomes payable in connection with delivery of the equipment, delays in the logistics process could affect the timing of our payment obligations and our financing plans. Any material delay,

damage, or cost overrun could delay our planned expansion, jeopardize milestones associated with MISO's ERAS program, increase project costs, and impair our ability to realize the anticipated benefits of the equipment, any of which could have a material adverse effect on our business, financial condition, cash flows, and results of operations.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

During the six months ended June 30, 2026, all sales and issuances of the Company’s equity securities were registered under the Securities Act of 1933, as amended. Accordingly, during the period covered by this report, the Company did not engage in any unregistered sales of its equity securities that would be required to be disclosed pursuant to Item 701 of Regulation S-K. For a description of the Company’s registered equity issuances during the year, including shares issued under the ATM Program and the CMPO, see Item 1. Financial Statements - Note 15 – “At Market Agreement (“ATM”) and Confidentially Marketed Public Offering (“CMPO”)” to our condensed consolidated financial statements.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

See Exhibit 95.1 to this Form 10-Q for a listing of our mine safety violations.

ITEM 5. OTHER INFORMATION

Rule 10b5-1 Trading Arrangements

During the second quarter of 2026, Heath Lovell, the Company's Chief Operating Officer, adopted a trading arrangement for the sale of shares of the Company's common stock that is intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) under the Securities Exchange Act of 1934 (a "Rule 10b5-1 trading arrangement"). The arrangement provides for the sale of up to 37,751 shares of the Company's common stock issuable upon the vesting and settlement of restricted stock units, and terminates on the earlier of December 31, 2027 or the completion of all sales under the arrangement.

During the three months ended June 30, 2026, no other director or officer of the Company adopted, modified, or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement as defined in Item 408(c).

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ITEM 6. EXHIBITS

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*Filed herewith.

++ Management Agreement

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​ HALLADOR ENERGY COMPANY

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Date: August 10, 2026 /s/BRENT K. BILSLAND

​ Brent K. Bilsland, Chairman, President and CEO

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Date: August 10, 2026 /s/TODD E. TELESZ

​ Todd E. Telesz, CFO

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Date: August 10, 2026 /s/ERIC VAN DEMAN

​ Eric Van Deman, CAO

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