Hallador Energy Company
11/09/2026 | Press release | Distributed by Public on 11/09/2026 16:30
Quarterly Report for Quarter Ending September 30, 2026 (Form 10-Q)
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis included in our Annual Report on Form 10-K for the year ended December 31, 2025 (the "2025 10-K"), is intended to assist in providing an understanding of changes in our results of operations and financial condition and is organized as follows:
•Forward-Looking Statements. This section provides a description of certain factors that could cause actual results or events to differ materially from anticipated results or events.
•Overview. This section provides a general description of our business and recent events.
•Material Changes in Results of Operations. This section provides an analysis of our results of operations for the three and nine months ended September 30, 2026 and 2025.
•Material Changes in Financial Condition. This section provides an analysis of our liquidity and our condensed consolidated statements of cash flows.
The capitalized terms used below have been defined in the notes to our condensed consolidated financial statements. In the following text, the terms "we," "our," "the Company" and "us" may refer, as the context requires, to Hallador Energy Company ("Hallador") or collectively to Hallador and its subsidiaries.
Unless otherwise indicated, operational data is presented as of September 30, 2026.
FORWARD-LOOKING STATEMENTS
Certain statements and information in this Quarterly Report on Form 10-Q may constitute "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, which are intended to be covered by the safe harbor provisions of those sections. These statements are based on our beliefs as well as assumptions made by, and information currently available to us. When used in this document, the words "anticipate," "believe," "continue," "could," "estimate," "expect," "forecast," "intend," "may," "plan," "potential," "project," "should," "target," "will," "would," and similar expressions or the negative thereof identify forward-looking statements. Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings and sources of funding, as well as statements regarding the development, financing, cost, timing, and completion of our 460 MW natural gas-fired peaking generation facility in Sullivan County, Indiana (the "Turtle Creek Project"); the delivery, financing, and deployment of the turbine equipment we have agreed to acquire and the related expansion of the Merom Generating Station (the "Merom Station"); the potential refinancing of our senior secured term loan facility entered into on September 15, 2026 with Kennedy Lewis Investment Management LLC ("KLIM") and the other lenders party thereto (the "KLIM Facility"); our contracted forward sales position and the revenue we expect to realize from it; the anticipated terms, effects, and regulatory approval of our power purchase and capacity agreements; the estimated useful life of the Merom Station; and our evaluation of strategic transactions are forward-looking statements. These statements reflect our current views with respect to future events as of the date of this Quarterly Report on Form 10-Q and are subject to numerous assumptions that we believe are open to a wide range of uncertainties and business risks, and actual results may differ materially from those expressed or implied in these statements. Among the factors that could cause actual results to differ from those in the forward-looking statements are:
•changes in macroeconomic and market conditions and market volatility, and the impact of such changes and volatility on our financial position;
•fluctuations in weather, natural gas and electricity commodity costs, inflation and economic conditions that impact demand of our customers and our operating results;
•the outcome or escalation of current international hostilities;
•changes in competition, or changes in electricity, natural gas or coal prices, demand, and availability which could affect our operating results and cash flows;
•risks associated with the expansion of our operations and properties, including through acquisitions and other strategic transactions, which may not be completed on anticipated terms, or at all;
•risks relating to our ability to fund and perform our obligations under the Asset Purchase Agreement (the "APA") with Energy World Corporation Ltd. for the acquisition of turbine equipment, including the sufficiency of the proceeds of the KLIM Facility and our ability to secure any additional financing for the remaining purchase price and related costs on a timely basis or at all, and the risk of default, forfeiture of amounts paid, or termination of the related agreements if we are unable to do so;
•risks relating to the international and domestic transportation, refurbishment, and delivery of the turbine equipment acquired under the APA, including delays, damage or loss in transit, and costs that exceed our current estimates;
•risks that we may be unable to deploy the turbine equipment acquired under the APA as planned, including because the Midcontinent Independent System Operator ("MISO") does not approve our Expedited Resource Addition Study ("ERAS") application or the related expansion project does not otherwise proceed, which could require us to sell the project together with the equipment or sell the equipment on a standalone basis, potentially at a loss;
•risks relating to our ability to participate in the MISO ERAS program, which ultimately requires the approval of MISO of our application and is a capital intensive project subject to construction, operational, financial, regulatory and legal risks that could impact the project's viability and/or timeline;
•risks relating to our ability to secure agreements in support of the development and construction of planned projects, including the expansion of the Merom Station through the ERAS program;
•risks relating to the development, financing, construction, commissioning, and operation of the Turtle Creek Project, including cost overruns from equipment, materials, labor or other expenses; delays; the performance of contractors, equipment suppliers, and other counterparties; the availability and cost of natural gas supply and pipeline transportation; permitting, interconnection, and other regulatory requirements; and our ability to achieve the Commercial Operation of the Turtle Creek Project (the date on which it does so, the "Commercial Operation Date") by the date required under the Credit Agreement governing the KLIM Facility (the "KLIM Credit Agreement"), the failure of which would constitute an event of default;
•risks relating to our indebtedness under the KLIM Facility, including its substantial cost, which reflects paid-in-kind ("PIK") interest and the premium payable upon repayment in full of the term loans to the extent necessary for each lender to have received cash payments and outstanding principal (including PIK interest) equal to at least 1.35 times its funded term commitment, increasing to 1.50 times if the maturity date is extended (the "MOIC Premium"); the financial and other covenants thereunder, including minimum unrestricted cash, debt service coverage, and leverage requirements and the limited cure rights available; mandatory prepayments from excess cash flow; increases in the PIK interest rate if the Closing Date Intercompany Loan is not repaid when required; the liens securing the KLIM Facility on substantially all of our assets, including the Merom Station and certain mining assets; restrictions on distributions and transfers of cash from Turtle Creek Gas Holdings, LLC ("Turtle Creek") and its subsidiaries; cross-default provisions; and our ability to refinance the KLIM Facility on or around the Commercial Operation Date on acceptable terms, or at all;
•risks arising from the fact that a portion of our contracted forward sales position is subject to regulatory approval or is based on our estimates rather than fixed commitments, including that the revenue we ultimately realize from our contracts could be materially lower than the amounts we have disclosed;
•legislation, regulations, administrative actions (e.g., executive orders), and court decisions and interpretations thereof, including those relating to the environment and the release of greenhouse gases ("GHG"), wastewater discharge and effluent limitation guidelines ("ELG"), coal combustion residuals, mining, miner health and safety, and health care, as well as those relating to data privacy protection;
•deregulation of the electric utility industry or the effects of any adverse change in the coal industry, electric utility industry, or general economic conditions;
•dependence on significant or long-term customer contracts, including renewing customer contracts upon expiration of existing contracts, and the risk that regulatory approvals (including from the Indiana Utility Regulatory Commission) or other conditions required for certain of our contracts are not obtained or satisfied on a timely basis, on acceptable terms, or at all;
•changes in the geopolitical environment in industries in which our customers operate;
•changes in attitude toward environmental, social, and governance ("ESG") matters among regulators, investors and parties with which we do business;
•the effect of changes in taxes or tariffs and other trade measures, including uncertainty regarding tariffs on imports into the United States, which could impact the Company's procurement and sourcing strategies;
•risks relating to inflation and increasing interest rates;
•liquidity constraints, including due to restrictions contained in our debt agreements or other arrangements, limitations on our access to cash held in restricted and project-level accounts, and those resulting from any future unavailability of financing;
•the effects of any future issuance of debt or equity securities, including dilution to our existing stockholders and the imposition of additional restrictive covenants;
•customer bankruptcies, a decline in customer creditworthiness, or customer cancellations or breaches to existing contracts, including failures to make payments when due;
•customer delays or failure to take coal or electricity under contracts;
•adjustments made in price, volume or terms to existing coal or electricity contracts;
•risks associated with our prepaid delivered energy contracts and other fixed-price commitments, including obligations to deliver electricity at prices that may be below prevailing market prices;
•our productivity levels and margins earned on our coal or electricity sales;
•supply chain disruptions and changes in equipment, raw material, service or labor costs or availability, including due to inflationary pressures;
•changes in the availability of skilled labor;
•our ability to maintain satisfactory relations with our employees;
•increases in labor costs, adverse changes in work rules, or cash payments or projections associated with workers' compensation claims;
•increases in transportation costs and risk of transportation delays or interruptions;
•operational interruptions due to geologic, permitting, labor, weather-related or other factors, including challenges in operating an aging coal-fired power plant, unplanned equipment failures, and forced or extended maintenance outages, such as those we experienced in the first half of 2026;
•the risk that the Merom Station may not continue to operate economically through its currently estimated useful life of 2040, including as a result of environmental compliance costs, market conditions, or regulatory changes, which could result in accelerated depreciation or impairment charges;
•risks associated with major mine-related or other accidents, mine fires, mine floods or other interruptions, including unanticipated operating conditions and other events that are not within our control;
•results of litigation, including claims not yet asserted;
•difficulty maintaining our surety bonds for mine reclamation;
•decline in or change in the coal industry's share of electricity generation, including as a result of environmental concerns related to coal mining and combustion and the cost and perceived benefits of other sources of electricity, such as natural gas, nuclear energy, and renewable fuels;
•risks resulting from natural disasters;
•difficulty in making accurate assumptions and projections regarding landfill and mine reclamation;
•uncertainties in estimating and replacing our coal reserves;
•the impact of current and potential changes to federal or state tax rules and regulations, including the effects of the One Big Beautiful Bill Act ("OBBBA") or a loss or reduction of benefits from certain tax deductions and credits;
•difficulty obtaining commercial property insurance;
•evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions;
•difficulty in making accurate assumptions and projections regarding future revenues and costs associated with equity investments in companies we do not control; and
•other factors, including those discussed in "Item 1A. Risk Factors" in our 2025 10-K (as supplemented by "Part II, Item 1A. Risk Factors" of this Quarterly Report on Form 10-Q) and in our other filings with the Securities and Exchange Commission ("SEC").
If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement. The foregoing list of factors is not exhaustive, and it is not possible for us to predict or identify all such risks and uncertainties. When considering forward-looking statements, you should also keep in mind the risk factors described in "Item 1A. Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2025, as supplemented by "Part II, Item 1A. Risk Factors" of this Quarterly Report on Form 10-Q and our subsequent filings with the SEC. The risk factors could also cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update or revise any forward-looking statements to reflect new information, future events or developments, unless required by applicable law. Forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q or, in the case of any other written or oral statement, the date on which it is made, and you should not place undue reliance on them. You should consider the information above when reading any forward-looking statements contained in this Quarterly Report on Form 10-Q; other reports filed by us with the SEC; our press releases; our website www.halladorenergy.com and written or oral statements made by us or any of our officers or other authorized persons acting on our behalf.
OVERVIEW
General
Hallador is a vertically integrated, independent power producer ("IPP") and fuel company with operations primarily in Indiana. The Company operates across multiple stages of the energy supply chain, from accredited capacity and energy to coal. The Company's electric operations are located within the MISO footprint. Our operations include Hallador Power Company, LLC ("Hallador Power"), which provides accredited capacity and energy to utilities and other energy market participants through its MISO interconnection, and Sunrise Coal, LLC ("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 Station, 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, 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 progress the development of the Turtle Creek Project, while monitoring opportunities to expand the capacity of our electric generation capabilities through further development, 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. ("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. In October 2026, the equipment was loaded onto an ocean-going vessel, was exported from the Philippines, and title and control of the equipment transferred to Hallador. In October 2026, we made the third and fourth installment payments under the APA totaling $315.0 million, consisting of a $50.0 million payment to the Seller and a $265.0 million payment into an escrow account held by the Seller. As of October 31, 2026, we had paid $349.8 million of the $350.0 million purchase price, including the escrowed amount, with the remaining approximately $0.2 million payable to third party vendors on behalf of the Seller. 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 15 - Commitments and Contingencies" to the condensed consolidated financial statements and "Liquidity and Capital Resources" below for additional information.
Energy and Capacity PPAs with Duke Energy Indiana. On October 7, 2026, Hallador Power entered into two agreements with Duke Energy Indiana, LLC (the "Indiana Utility"); a six year Power Purchase agreement (the "Energy PPA"), which contains an annual average base energy quantity of 200 MW of electricity from the Merom Station, and an agreement under a Master Power Purchase and Sale Agreement (the "Capacity PPA"), under which Hallador Power will sell the Indiana Utility certain Zonal Resource Credits. Both agreements run from June 1, 2029 through May 31, 2035. See "Note 7 - Revenue" to the condensed consolidated financial statements for additional information.
KLIM Facility. On September 15, 2026, Hallador and its wholly-owned subsidiary, Turtle Creek, each as a co-borrower, jointly and severally liable for all obligations thereunder, entered into the KLIM Credit Agreement with KLIM, acting for certain managed or advised funds and accounts, the other lenders from time to time party thereto, U.S. Bank Trust Company, National Association, as administrative agent, and U.S. Bank National Association, as collateral agent. The KLIM Credit Agreement provides for the KLIM Facility, a $600.0 million senior secured term loan facility, with $550.0 million funded at closing and a $50.0 million delayed draw available for 12 months after closing, subject to an agreed draw schedule and funding conditions. The KLIM Facility is secured by substantially all of our assets, including the Merom Station and certain mining assets, requires payment of the MOIC Premium upon repayment, and includes an event of default if the Commercial Operation Date has not occurred on or before June 30, 2029. See "Note 5 - Debt" to the condensed consolidated financial statements for additional information.
Turtle Creek Project Summary. The Turtle Creek Project is a 460-MW natural gas-fired peaking generation facility in Sullivan County, Indiana, to be owned and operated by Turtle Creek Gas and expected to reach commercial operation in the second half of 2028. Hallador took title and control of the turbine equipment in October 2026 and completed payment of the third and fourth installments under the APA. The October payments were paid from Turtle Creek funds, including the construction account established under the KLIM Facility. The tables below summarize the project's equipment purchase, capitalized costs and financing, and the change in construction work in progress by project. See "Note 3 - Restricted Cash," "Note 5 - Debt" and "Note 15 - Commitments and Contingencies."
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Turtle Creek Project (in millions)
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| Equipment purchase under the APA | ||||||||
| Purchase price | $ | 350.0 | ||||||
| Paid through September 30, 2026 | 23.8 | |||||||
| Paid October 1 through October 31, 2026 | 326.0 | |||||||
| Remaining payable to third party vendors on behalf of the Seller | 0.2 | |||||||
| Other project costs | ||||||||
| Expected transportation, refurbishment, insurance, and logistics costs | $ | ~100.0 | ||||||
| Costs capitalized in construction work in progress at September 30, 2026 | $ | 53.1 | ||||||
| Financing and cash | ||||||||
| KLIM Facility, funded September 15, 2026 | $ | 550.0 | ||||||
| KLIM Facility, delayed draw term loan commitment (available only for the Turtle Creek Project) | 50.0 | |||||||
| Construction account (restricted cash) at September 30, 2026 | 294.0 | |||||||
| Cash held by Turtle Creek at October 31, 2026 | $ | 34.1 | ||||||
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Construction work in progress (in millions)
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| 9/30/2026 | 12/31/2025 | Change | ||||||||||||||||||||||||
| Turtle Creek Project | $ | 53.1 | $ | 13.6 | $ | 39.5 | ||||||||||||||||||||
| Merom, including ELG | 34.1 | 26.1 | 8.0 | |||||||||||||||||||||||
| Other power projects | 4.7 | - | 4.7 | |||||||||||||||||||||||
| Total | $ | 92.0 | $ | 39.7 | $ | 52.3 | ||||||||||||||||||||
Competition and Other External Factors
We are experiencing competition in both our Electric and Coal Operations. This competition has the potential to drive 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.
MATERIAL CHANGES IN RESULTS OF OPERATIONS
Forward Sales Position 1
| 2026 | 2027 | 2028 | 2029 | 2030 | 2031 - 2035 | 2036 - 2040 | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Power | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Accredited Capacity | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Average daily contracted accredited capacity MW | 727 | 789 | 768 | 750 | 725 | 697 | 500 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Average contracted accredited capacity price per MWd | $ | 244 | $ | 262 | $ | 324 | $ | 478 | $ | 502 | $ | 499 | $ | 480 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Contracted accredited capacity revenue (in millions) | $ | 16.31 | $ | 75.31 | $ | 90.95 | $ | 130.97 | $ | 132.75 | $ | 635.49 | $ | 386.85 | $ | 1,468.64 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Energy ² | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Contracted MWh (in millions) | 1.31 | 3.59 | 1.92 | 1.59 | 1.41 | 6.14 | - | 15.96 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Average contracted price per MWh | $ | 42.93 | $ | 44.68 | $ | 44.99 | $ | 44.47 | $ | 47.73 | $ | 50.91 | $ | - | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Contracted revenue (in millions) | $ | 56.28 | $ | 160.25 | $ | 86.57 | $ | 70.77 | $ | 67.18 | $ | 312.47 | $ | - | $ | 753.53 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total Accredited Capacity & Energy Revenue per MWh ³ | $ | 46.07 | $ | 59.16 | $ | 62.48 | $ | 69.66 | $ | 73.26 | $ | 75.35 | NM | $ | 68.04 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total Accredited Capacity & Energy Revenue (in millions) | $ | 72.59 | $ | 235.56 | $ | 177.52 | $ | 201.75 | $ | 199.93 | $ | 947.96 | $ | 386.85 | $ | 2,222.16 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Coal | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Priced tons - 3rd party (in millions) | 0.92 | 2.79 | 0.75 | - | - | - | - | 4.46 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Avg price per ton - 3rd party | $ | 55.89 | $ | 57.27 | $ | 59.50 | - | - | - | - | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Contracted coal revenue - 3rd party (in millions) | $ | 51.25 | $ | 159.84 | $ | 44.63 | $ | - | $ | - | $ | - | $ | - | $ | 255.72 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED | $ | 123.85 | $ | 395.41 | $ | 222.15 | $ | 201.75 | $ | 199.93 | $ | 947.96 | $ | 386.85 | $ | 2,477.89 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Priced tons - Intercompany (in millions) | 1.58 | 1.50 | 2.02 | 2.02 | 2.02 | - | - | 9.16 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Avg price per ton - Intercompany | $ | 51.00 | $ | 55.00 | $ | 56.00 | 57.00 | 58.00 | - | - | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Contracted coal revenue - Intercompany (in millions) | $ | 80.78 | $ | 82.50 | $ | 113.34 | $ | 115.37 | $ | 117.39 | $ | - | $ | - | $ | 509.39 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT | $ | 204.63 | $ | 477.91 | $ | 335.49 | $ | 317.12 | $ | 317.32 | $ | 947.96 | $ | 386.85 | $ | 2,987.27 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
1Total Forward Sales Position as of September 30, 2026, including the impacts of both the Energy PPA and the Capacity PPA executed on October 7, 2026. 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 October 1, 2026 through December 31, 2026.
2 The Energy PPA executed October 7, 2026 has an annual average base energy quantity of 200 MW. The contract is unit contingent, such that when one or both power generating units at the Merom Station is not producing energy above a certain threshold, the base quantities are reduced proportionate to the number of power generating units in operation. The contract also contains a volume option that permits the counterparty to reduce the base quantity to zero for a maximum of 90 days per year. For purposes of the table above, we have included management's estimates of the energy quantities and revenue based on comparisons to forward energy curve pricing. For the 2029, 2030, and 2031 - 2035 periods in the table above, we have estimated total energy quantities of 0.9 million MWh, 1.4 million MWh, and 6.1 million MWh, respectively, and estimated revenue of approximately $41.8 million, $67.2 million, and $312.5 million, respectively. These estimates are forward-looking statements and could vary materially from actual volumes and revenue, including variations due to the factors described above.
3 Total Accredited Capacity & Energy Revenue per MWh combines the average contracted price per MWh for energy with the quotient of the contracted accredited capacity revenue divided by annual generation of 5.2 million MWh per year, which represents annualized average generator verification test capacity (GVTC) multiplied by HNRG's average equipment availability factor (EAF), less 15-20% allowances for sub-optimal conditions. Contracted energy pricing is currently established only through 2035; accordingly, the figure for 2036-2040 is not meaningful as no energy revenue is contracted for that period. The Total column reflects 2026-2035, the period for which both energy and capacity pricing are currently under contract.
NM - Not meaningful
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
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||||||||||||||
| (in thousands) | (in thousands) | |||||||||||||||||||||||||||||||||||||
| Delivered Energy | $ | 74,169 | $ | 77,776 | $ | 167,313 | $ | 194,044 | ||||||||||||||||||||||||||||||
| Accredited Capacity Revenue | 18,677 | 15,459 | 52,819 | 45,110 | ||||||||||||||||||||||||||||||||||
| Electric Sales | $ | 92,846 | $ | 93,235 | $ | 220,132 | $ | 239,154 | ||||||||||||||||||||||||||||||
| Fuel | $ | (43,440) | $ | (44,751) | $ | (96,258) | $ | (104,150) | ||||||||||||||||||||||||||||||
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Other Operating Costs 1
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- | (1) | (1) | (10) | ||||||||||||||||||||||||||||||||||
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Other Operating and Maintenance Costs 2
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(7,093) | (9,368) | (32,252) | (24,602) | ||||||||||||||||||||||||||||||||||
| Cost of Purchased Power | (11,103) | (2,074) | (34,599) | (11,086) | ||||||||||||||||||||||||||||||||||
| Utilities | (2,291) | (1,873) | (6,387) | (3,932) | ||||||||||||||||||||||||||||||||||
| Labor | (9,798) | (7,949) | (26,549) | (23,731) | ||||||||||||||||||||||||||||||||||
| General and Administrative | (1,508) | (1,308) | (4,299) | (3,972) | ||||||||||||||||||||||||||||||||||
| Segment EBITDA | 17,613 | 25,911 | 19,787 | 67,671 | ||||||||||||||||||||||||||||||||||
| Other Operating Revenue | 149 | 170 | 517 | 3,372 | ||||||||||||||||||||||||||||||||||
| Depreciation, Depletion and Amortization | (3,081) | (5,131) | (14,949) | (15,456) | ||||||||||||||||||||||||||||||||||
| Asset Retirement Obligations Accretion | (137) | (126) | (401) | (369) | ||||||||||||||||||||||||||||||||||
| Interest Income | 620 | 22 | 694 | 41 | ||||||||||||||||||||||||||||||||||
| Interest Expense | (4,138) | (2,585) | (9,501) | (6,208) | ||||||||||||||||||||||||||||||||||
| Income (Loss) before Income Taxes | $ | 11,026 | $ | 18,261 | $ | (3,853) | $ | 49,051 | ||||||||||||||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||||||||||||||
| (in thousands) | (in thousands) | |||||||||||||||||||||||||||||||||||||
| (per MWh) | (per MWh) | |||||||||||||||||||||||||||||||||||||
| MWh Generated (in thousands) | 1,408 | 1,530 | 3,143 | 3,706 | ||||||||||||||||||||||||||||||||||
| MWh Purchased (in thousands) | 145 | 48 | 513 | 264 | ||||||||||||||||||||||||||||||||||
| MWh Sold (in thousands) | 1,553 | 1,578 | 3,656 | 3,970 | ||||||||||||||||||||||||||||||||||
| Delivered Energy | $ | 47.76 | $ | 49.29 | $ | 45.76 | $ | 48.88 | ||||||||||||||||||||||||||||||
| Accredited Capacity Revenue | 12.03 | 9.80 | 14.45 | 11.36 | ||||||||||||||||||||||||||||||||||
| Electric Sales | $ | 59.79 | $ | 59.08 | $ | 60.21 | $ | 60.24 | ||||||||||||||||||||||||||||||
| Fuel | $ | (27.97) | $ | (28.36) | $ | (26.33) | $ | (26.23) | ||||||||||||||||||||||||||||||
|
Other Operating Costs 1
|
- | - | - | - | ||||||||||||||||||||||||||||||||||
|
Other Operating and Maintenance Costs 2
|
(4.57) | (5.94) | (8.82) | (6.20) | ||||||||||||||||||||||||||||||||||
| Cost of Purchased Power | (7.15) | (1.31) | (9.46) | (2.79) | ||||||||||||||||||||||||||||||||||
| Utilities | (1.48) | (1.19) | (1.75) | (0.99) | ||||||||||||||||||||||||||||||||||
| Labor | (6.31) | (5.04) | (7.26) | (5.98) | ||||||||||||||||||||||||||||||||||
| General and Administrative | (0.97) | (0.83) | (1.18) | (1.00) | ||||||||||||||||||||||||||||||||||
| Segment EBITDA | 11.34 | 16.42 | 5.41 | 17.05 | ||||||||||||||||||||||||||||||||||
| Other Operating Revenue | 0.10 | 0.11 | 0.14 | 0.85 | ||||||||||||||||||||||||||||||||||
| Depreciation, Depletion and Amortization | (1.98) | (3.25) | (4.09) | (3.89) | ||||||||||||||||||||||||||||||||||
| Asset Retirement Obligations Accretion | (0.09) | (0.08) | (0.11) | (0.09) | ||||||||||||||||||||||||||||||||||
| Interest Income | 0.40 | 0.01 | 0.19 | 0.01 | ||||||||||||||||||||||||||||||||||
| Interest Expense | (2.66) | (1.64) | (2.60) | (1.56) | ||||||||||||||||||||||||||||||||||
| Income (Loss) before Income Taxes | $ | 7.10 | $ | 11.57 | $ | (1.05) | $ | 12.36 | ||||||||||||||||||||||||||||||
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.
Q3 2026 vs. Q3 2025
Segment operating revenues from electric operations decreased $0.4 million, or 0.4%, compared to the third quarter of 2025, attributable to a $3.6 million decrease in sales of delivered energy that was partially offset by a $3.2 million increase in accredited capacity revenue. The price per MWh for delivered energy decreased 3.1% year-over-year from $49.29 for the three-month period ended September 30, 2025 to $47.76 in 2026, primarily attributable to contract mix, driven by increased deliveries under lower-priced prepaid forward sales contracts. Our Electric Operations generated 0.1 million lower MWh, offset by the purchase of an additional 0.1 million MWh for resale resulting in a 1.6% reduction in total MWh sold compared to the third quarter of 2025. Accredited capacity revenue increased 20.8% to $18.7 million for the three-month period ended September 30, 2026 from $15.5 million in the comparable prior year period driven by improved prices.
Fuel costs on a segment basis decreased $1.3 million, or 2.9%, from the third quarter of 2025. The decrease includes a $2.6 million coal inventory adjustment recorded in the third quarter of 2025 that did not recur in 2026, partially offset by higher non-coal fuel costs, primarily fuel oil consumed during the start-ups. Coal costs decreased $0.3 million, due to lower electric power generation of 8.0% and the benefit of the coal mix used, partially offset by a higher burn rate and an increase in the cost of coal consumed of 2.4%, from $54.22 per ton in 2025 to $55.51 per ton in 2026. Fuel costs on a consolidated basis increased $1.6 million, or 6.1%, reflecting a heavier reliance on coal from third-parties combined with a 6.2% increase in the average price per ton of coal purchased from third parties. Weather and natural gas pricing had a muted impact on the demand for coal, as the average spot price at Chicago citygate increased $0.10 per thousand cubic feet to $3.75 per thousand cubic feet in July 2026 compared to July 2025.
Other operating and maintenance costs decreased $2.3 million, or 24.3%, from the third quarter of 2025, primarily because the 2025 planned maintenance outage was phased later in the year with more of the planned maintenance activities extending into the third quarter in 2025 in comparison to the planned maintenance outage in 2026. This was partially offset
by higher consumable supplies and maintenance services associated with unplanned outages during the third quarter of 2026.
Cost of purchased power increased $9.0 million, or 435.3%, from the third 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 202.1% that was further impacted by the energy pricing dynamics at the time of the purchases.
Labor expenses increased $1.8 million or 23.3% for the third quarter of 2026 versus the comparable period in 2025 driven by the impact of incremental maintenance efforts associated with the completion of the 2026 planned major maintenance outage in combination with annual wage increases.
Depreciation, depletion and amortization decreased $2.1 million, or 40.0%, from the third quarter of 2025 as lower depreciation expense from extending the estimated useful lives of the Merom Station and related assets through 2040, was only partially offset by incremental depreciation from recent capital expenditures placed in service. The change in estimated useful life was accounted for prospectively beginning in the second quarter of 2026 as a change in accounting estimate and decreased depreciation expense by $3.6 million for the three months ended September 30, 2026. See "Note 1 - Basis of Presentation" to the condensed consolidated financial statements for further information.
Interest expense increased $1.6 million, or 60.1%, from the third quarter of 2025. The increase primarily relates to interest on the KLIM Facility, which was funded on September 15, 2026 ($2.7 million, net of $0.2 million of capitalized interest), partially offset by lower accretion on our prepaid delivered energy contracts ($1.9 million compared to $2.4 million) as the contract liability balance declined. Hallador has not entered into any new prepaid delivered energy contracts in 2026.
Income before income taxes decreased $7.2 million from $18.3 million in the third quarter of 2025 to $11.0 million in the third quarter of 2026, which is attributable to the items described in the discussion above.
YTD 2026 vs. YTD 2025
Segment operating revenues from electric operations for the nine months ended September 30, 2026 decreased $19.0 million, or 8.0% compared to the first nine months of 2025, attributable to a $26.7 million decrease in sales of delivered energy partially offset by a $7.7 million increase in accredited capacity revenue. Our Electric Operations generated 0.6 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 7.9% compared to the first nine months 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 6.4% year-over-year from $48.88 for the nine-month period ended September 30, 2025 to $45.76 in 2026. Accredited capacity revenue increased 17.1% to $52.8 million for the nine-month period ended September 30, 2026 from $45.1 million in the comparable prior year period.
Fuel costs on a segment basis decreased $7.9 million, or 7.6%, from the first nine months of 2025. The decrease is due to electric power generation falling by 0.6 million MWh, or 15.2%. We consumed 0.2 million fewer tons of coal on both a segment and consolidated basis in 2026 compared to 2025. Equipment issues experienced during the first quarter of 2026 accounted for 0.5 million MWh of the 0.6 million MWh decline in generation for the nine months ended September 30, 2026. The decrease was partially offset by an increase in the cost of coal consumed from $53.88 per ton in 2025 to $55.05 per ton in 2026 and by $2.3 million of additional fuel oil consumed during start-ups associated with the equipment issues noted above. Fuel costs on a consolidated basis increased $1.8 million, or 3.1% to $59.2 million for the nine months ended September 30, 2026.
Other operating and maintenance costs increased $7.7 million, or 31.1%, from the first nine months of 2025. The increase was driven by $4.3 million of additional costs associated with the more significant scope of the planned major maintenance outage completed in 2026, a $1.8 million increase in property insurance premiums, and $1.9 million of higher consumable supplies, materials and maintenance services reflecting the equipment issues experienced at Merom. The impacted generating unit returned to service in July 2026.
Cost of purchased power increased $23.5 million, or 212.1%, versus the nine-month period ended September 30, 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 94.3% that was further impacted by the energy pricing dynamics at the time of the purchases.
Utilities expense increased $2.5 million, or 62.4%, compared to 2025, which was largely attributable to the frequency and timing of energy intensive start-ups of the generating units during the first half of 2026.
Labor expenses increased $2.8 million, or 11.9% in the nine-month period ended September 30, 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 84.7% compared to the first nine months of 2025. This decrease primarily reflects the $3.0 million exclusivity agreement fee recognized in the second quarter of 2025.
Depreciation, depletion and amortization decreased $0.5 million, or 3.3%, compared to the first nine months of 2025, driven by a $4.8 million decrease resulting from the change in the estimated useful life of the Merom Station described above partially offset by capital additions placed in service.
Interest expense increased $3.3 million, or 53.0%, during the nine-month period ended September 30, 2026 versus the comparable period in 2025. The increase in our interest expense primarily relates to interest on the KLIM Facility ($2.7 million) and a $1.4 million increase in accretion on our prepaid delivered energy contracts entered into in 2024 and 2025. Hallador has not entered into any new prepaid delivered energy contracts in 2026.
Income before income taxes decreased $52.9 million from $49.1 million of income before taxes in the first nine months of 2025 to a loss before taxes of $3.9 million in the first nine months of 2026, which is attributable to the items described in the discussion above.
Coal Operations
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||||||||||||||
| (in thousands) | (in thousands) | |||||||||||||||||||||||||||||||||||||
| Coal Sales | $ | 50,631 | $ | 68,814 | $ | 147,917 | $ | 169,117 | ||||||||||||||||||||||||||||||
| Fuel | $ | (779) | $ | (574) | $ | (2,093) | $ | (1,564) | ||||||||||||||||||||||||||||||
| Other Operating and Maintenance Costs | (24,482) | (35,046) | (67,582) | (77,147) | ||||||||||||||||||||||||||||||||||
| Utilities | (2,817) | (2,670) | (8,695) | (9,270) | ||||||||||||||||||||||||||||||||||
| Labor | (20,690) | (19,625) | (60,139) | (57,671) | ||||||||||||||||||||||||||||||||||
| General and Administrative | (2,397) | (2,062) | (6,826) | (6,290) | ||||||||||||||||||||||||||||||||||
| Segment EBITDA | (534) | 8,837 | 2,582 | 17,175 | ||||||||||||||||||||||||||||||||||
| Other Operating Revenue | 696 | 1,582 | 2,624 | 4,206 | ||||||||||||||||||||||||||||||||||
| Depreciation, Depletion and Amortization | (4,523) | (3,992) | (13,128) | (14,148) | ||||||||||||||||||||||||||||||||||
| ARO Accretion | (290) | (320) | (850) | (941) | ||||||||||||||||||||||||||||||||||
| Exploration Costs | (36) | (38) | (407) | (157) | ||||||||||||||||||||||||||||||||||
| (Loss) Gain on Disposal or Abandonment of Assets, Net | (343) | 2,334 | (157) | 2,410 | ||||||||||||||||||||||||||||||||||
| Interest Income | 114 | 65 | 465 | 164 | ||||||||||||||||||||||||||||||||||
| Interest Expense | (111) | (2,342) | (1,052) | (6,261) | ||||||||||||||||||||||||||||||||||
| Income (Loss) before Income Taxes | $ | (5,027) | $ | 6,126 | $ | (9,923) | $ | 2,448 | ||||||||||||||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||||||||||||||
| (in thousands) | (in thousands) | |||||||||||||||||||||||||||||||||||||
| (per ton) | (per ton) | |||||||||||||||||||||||||||||||||||||
| Tons Sold (in thousands) | 935 | 1,355 | 2,723 | 3,316 | ||||||||||||||||||||||||||||||||||
| Coal Sales | $ | 54.17 | $ | 50.79 | $ | 54.33 | $ | 51.00 | ||||||||||||||||||||||||||||||
| Fuel | $ | (0.83) | $ | (0.42) | $ | (0.77) | $ | (0.47) | ||||||||||||||||||||||||||||||
| Other Operating and Maintenance Costs | (26.19) | (25.86) | (24.82) | (23.27) | ||||||||||||||||||||||||||||||||||
| Utilities | (3.01) | (1.97) | (3.19) | (2.80) | ||||||||||||||||||||||||||||||||||
| Labor | (22.14) | (14.48) | (22.09) | (17.39) | ||||||||||||||||||||||||||||||||||
| General and Administrative | (2.56) | (1.52) | (2.51) | (1.90) | ||||||||||||||||||||||||||||||||||
| Segment EBITDA | (0.56) | 6.54 | 0.95 | 5.17 | ||||||||||||||||||||||||||||||||||
| Other Operating Revenue | 0.74 | 1.17 | 0.96 | 1.27 | ||||||||||||||||||||||||||||||||||
| Depreciation, Depletion and Amortization | (4.84) | (2.95) | (4.82) | (4.27) | ||||||||||||||||||||||||||||||||||
| ARO Accretion | (0.31) | (0.24) | (0.31) | (0.28) | ||||||||||||||||||||||||||||||||||
| Exploration Costs | (0.04) | (0.03) | (0.15) | (0.05) | ||||||||||||||||||||||||||||||||||
| (Loss) Gain on Disposal or Abandonment of Assets, Net | (0.37) | 1.72 | (0.06) | 0.73 | ||||||||||||||||||||||||||||||||||
| Interest income | 0.12 | 0.05 | 0.17 | 0.05 | ||||||||||||||||||||||||||||||||||
| Interest expense | (0.12) | (1.73) | (0.39) | (1.89) | ||||||||||||||||||||||||||||||||||
| Loss on Extinguishment of Debt | - | - | - | - | ||||||||||||||||||||||||||||||||||
| Income (Loss) before Income Taxes | $ | (5.38) | $ | 4.53 | $ | (3.65) | $ | 0.73 | ||||||||||||||||||||||||||||||
Q3 2026 vs. Q3 2025
Segment operating revenue from coal operations (including intercompany sales to Merom) decreased $18.2 million, or 26.4%, compared to the third quarter of 2025. The decrease was driven by lower volume partially offset by an increase in the average sales price for our coal. We sold 0.9 million tons of coal during the third quarter of 2026, a decrease of 0.4 million tons, or 31.0%, versus 2025. Our average sales price, on a segment basis, increased $3.38 per ton from $50.79 per ton to $54.17 per ton. Sunrise sold 16.9% fewer tons to Merom during the third quarter of 2026 compared to 2025, as Merom drew down its coal inventory, while tons sold to third parties decreased 0.4 million tons, or 35.8%. On a consolidated basis, third party sales decreased $15.1 million, or 29.5%, versus the third quarter of 2025, as the decrease in tons sold was partially offset by a 9.9% increase in our average third party price per ton from $50.79 in 2025 to $55.80 in 2026.
Other operating and maintenance costs decreased $10.6 million, or 30.1%, which is largely attributable to the 0.4 million, or 31.0%, reduction in tons sold, partially offset by higher mine expansion costs, versus the third quarter of 2025. Labor expenses increased $1.1 million, or 5.4%, from the third quarter of 2025 largely attributable to annual pay increases for our coal operations employees; however, because tons sold declined 31.0%, and labor costs are largely fixed, labor cost per ton sold rose $7.66 to $22.14 per ton.
Depreciation, Depletion and Amortization increased by $0.5 million, or 13.3%, compared to the third quarter of 2025, largely attributable to new and refurbished mining equipment placed in service over the past 12 months.
Interest expense decreased $2.2 million, or 95.3%, from $2.3 million for the three months ended September 30, 2025. The decrease is attributable to the paydown of the Company's prior bank facility in March 2026, while the new bank facility is not held within the Coal Operations segment.
Income before income taxes decreased by $11.2 million from income before income taxes of $6.1 million in the third quarter of 2025 to a loss before income taxes of $5.0 million in 2026. The main drivers of this change in income (loss) before income taxes are described in the discussion above.
YTD 2026 vs. YTD 2025
Segment operating revenue from coal operations (including intercompany sales to Merom) decreased $21.2 million, or 12.5%, compared to the nine months ended September 30, 2025. The decrease was driven by lower volume partially offset by an increase in the average sales price for our coal. We sold 2.7 million tons of coal during the first nine months of 2026, a decrease of 0.6 million tons, or 17.9%, versus 2025. Our average sales price, on a segment basis, increased $3.33 per ton from $51.00 per ton to $54.33 per ton. Sunrise sold 0.3 million fewer tons of coal to Merom due to the aforementioned equipment issues, while tons sold to third parties decreased 14.3%. On a consolidated basis, third party sales decreased $7.8 million, or 6.5%, versus the first nine months of 2025, as the decrease in tons sold was partially offset by a 9.1% increase in our average third party price per ton from $51.08 in 2025 to $55.72 in 2026.
Other operating and maintenance costs decreased $9.6 million, or 12.4%, which is largely attributable to the 0.6 million, or 17.9%, reduction in tons sold versus 2025, partially offset by higher mine expansion costs. Labor expenses increased $2.5 million, or 4.3%, from the nine months ended September 30, 2025; however, because tons sold declined 17.9%, and labor costs are largely fixed, labor cost per ton sold rose $4.70 to $22.09 per ton.
Depreciation, Depletion and Amortization decreased by $1.0 million, or 7.2%, compared to the first nine months of 2025.
Interest expense decreased $5.2 million, or 83.2%, from $6.3 million for the nine months ended September 30, 2025 to $1.1 million in 2026. The decrease is attributable to the paydown of the Company's prior bank facility in March 2026, while the new bank facility is not held within the Coal Operations segment.
Income (loss) before income taxes decreased by $12.4 million from income before income taxes of $2.4 million in the first nine months of 2025 to a loss before income taxes of $9.9 million in the nine-month period ended September 30, 2026. The main drivers of this change in income (loss) before income taxes are described in the discussion above.
Quarterly coal sales and cost data on a segment basis are as follows (in thousands, except per ton data and wash plant recovery percentage):
| All Mines | 4th 2025 | 1st 2026 | 2nd 2026 | 3rd 2026 | T4Qs | ||||||||||||||||||||||||||||||||||||||||||
| Tons produced | 905 | 907 | 954 | 901 | 3,667 | ||||||||||||||||||||||||||||||||||||||||||
| Tons sold | 995 | 854 | 934 | 935 | 3,718 | ||||||||||||||||||||||||||||||||||||||||||
| Wash plant recovery in % | 57 | % | 59 | % | 63 | % | 62 | % | |||||||||||||||||||||||||||||||||||||||
| Capex (Coal Operations) | $ | 6,449 | $ | 3,792 | $ | 4,038 | $ | 4,606 | $ | 18,885 | |||||||||||||||||||||||||||||||||||||
| Capex per ton sold (Coal Operations) | $ | 6.48 | $ | 4.44 | $ | 4.32 | $ | 4.93 | $ | 5.08 | |||||||||||||||||||||||||||||||||||||
|
Average cost per ton sold1
|
$ | 46.75 | $ | 50.66 | $ | 49.77 | $ | 52.17 | |||||||||||||||||||||||||||||||||||||||
| All Mines | 4th 2024 | 1st 2025 | 2nd 2025 | 3rd 2025 | T4Qs | ||||||||||||||||||||||||||||||||||||||||||
| Tons produced | 971 | 1,020 | 1,059 | 1,034 | 4,084 | ||||||||||||||||||||||||||||||||||||||||||
| Tons sold | 875 | 1,071 | 890 | 1,355 | 4,191 | ||||||||||||||||||||||||||||||||||||||||||
| Wash plant recovery in % | 62 | % | 64 | % | 66 | % | 64 | % | |||||||||||||||||||||||||||||||||||||||
| Capex (Coal Operations) | $ | 11,079 | $ | 6,244 | $ | 5,793 | $ | 6,873 | $ | 29,989 | |||||||||||||||||||||||||||||||||||||
| Capex per ton sold (Coal Operations) | $ | 12.66 | $ | 5.83 | $ | 6.51 | $ | 5.07 | $ | 7.16 | |||||||||||||||||||||||||||||||||||||
|
Average cost per ton sold1
|
$ | 43.25 | $ | 43.65 | $ | 46.03 | $ | 42.74 | |||||||||||||||||||||||||||||||||||||||
1 Average cost per ton sold is calculated as the sum of the Coal Operation's fuel, other operating and maintenance costs, utilities and labor costs divided by tons sold for the respective period in this table. Coal Operations costs are presented in the "Discussion and Analysis of our Reportable Segments" above.
EARNINGS (LOSS) PER SHARE
| 4th 2025 | 1st 2026 | 2nd 2026 | 3rd 2026 | |||||||||||||||||||||||||||||||||||
| Basic | $ | (0.01) | $ | (0.20) | $ | (0.32) | $ | (0.10) | ||||||||||||||||||||||||||||||
| Diluted | $ | (0.01) | $ | (0.20) | $ | (0.32) | $ | (0.10) | ||||||||||||||||||||||||||||||
| 4th 2024 | 1st 2025 | 2nd 2025 | 3rd 2025 | |||||||||||||||||||||||||||||||||||
| Basic | $ | (5.06) | $ | 0.23 | $ | 0.19 | $ | 0.56 | ||||||||||||||||||||||||||||||
| Diluted | $ | (5.06) | $ | 0.23 | $ | 0.19 | $ | 0.55 | ||||||||||||||||||||||||||||||
INCOME TAXES
Our effective tax rate ("ETR") is estimated at ~0% for the nine months ended September 30, 2026 and 2025, respectively. Income tax expense of $1.8 million was recorded in the three months ended September 30, 2026, compared with a year-to-date income tax benefit of $1.7 million recorded through June 30, 2026. The change reflects a decrease in our estimated annual ETR. At June 30, 2026, we forecasted full-year pretax income, whereas at September 30, 2026, we forecast a full-year pretax loss, primarily due to financing costs related to the KLIM Facility, including the loss on extinguishment of the TCB Credit Facility and interest expense, and expected operating results. Our annual income tax estimate primarily reflects the change in our net deferred tax liability that is not offset by net operating loss carryforwards, which are limited to 80% of taxable income. For the nine months ended September 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 the valuation allowance and, historically, statutory 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.
RESTRICTED STOCK GRANTS
See "Item 1. Financial Statements - Note 9 - 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 $433.0 million of cash and restricted cash as of September 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. For the details of the borrowing capacity under our credit facility, see "Item 1. Financial Statements - Note 5 - 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 September 30, 2026 unaudited condensed consolidated balance sheet. In this regard, we have commitments and contingent obligations related to (a) the acquisition of equipment under the APA, (b) leases of railcars that qualify for the short-term lease exception (c) certain operating costs associated with our Electric Operations and our Coal Operations, and (d) the MOIC Premium that would be payable upon repayment of the KLIM Facility, as described under "Capitalization" below.
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 acceptable terms, or at all.
Liquidity consists of our additional borrowing capacity and unrestricted cash and cash equivalents. As of September 30, 2026, we did not have additional borrowing capacity under the KLIM Facility and total liquidity of $103.2 million. Our liquidity is net of $19.7 million in outstanding letters of credit that were cash collateralized as of September 30, 2026 to maintain surety bonds and other credit support obligations.
Turbine Equipment Acquisition
As of September 30, 2026, we had paid $23.8 million of the purchase price under the APA in the form of payments to third party vendors made on behalf of the Seller and had a remaining balance of the purchase price of approximately $326.2 million. In October 2026, we paid $326.0 million of the remaining balance, including the third and fourth installments under the APA of $315.0 million ($50.0 million to the Seller and $265.0 million into an escrow account held by the Seller, to which we do not have access), and title to the equipment transferred to us. As of October 31, 2026, we had paid $349.8 million of the $350.0 million purchase price, with approximately $0.2 million remaining payable to third party vendors on behalf of the Seller, which will be paid in accordance with the APA. The escrowed amount is not available to fund our other cash requirements. The approximately $100.0 million of expected transportation, refurbishment, insurance, and logistics costs, together with the remaining costs of the Turtle Creek Project, represents a material cash requirement. We expect to fund these costs with cash on hand, cash from operations, and the delayed draw term loan commitment under the KLIM Facility, which is available only to fund the Turtle Creek Project, subject to funding conditions. The Turtle Creek Project may also require incremental external funding. No assurance can be given that any external funding would be available to us on acceptable terms, or at all.
Consolidated Statement of Cash Flows Summary.
The unaudited condensed consolidated statements of cash flows are summarized as follows for the periods presented:
|
Nine Months Ended September 30, |
||||||||||||||||||||
| 2026 | 2025 | Change | ||||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Net cash provided by (used in) operating activities | $ | (25.1) | $ | 73.0 | $ | (98.1) | ||||||||||||||
| Net cash used in investing activities | (90.9) | (41.8) | (49.1) | |||||||||||||||||
| Net cash provided by (used in) financing activities | 533.6 | (7.9) | 541.5 | |||||||||||||||||
| Increase in cash, cash equivalents, and restricted cash | $ | 417.6 | $ | 23.3 | $ | 394.3 | ||||||||||||||
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) lower cash receipts from prepaid forward sales contracts, partially offset by incremental cash received for annual sales of accredited capacity compared to 2025 and lower cash payments of interest. Consolidated Adjusted EBITDA is a measure that is not calculated in accordance with U.S. generally accepted accounting principles ("GAAP"), 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 $46.8 million attributable to incremental capital expenditure projects of $13.7 million at Merom and an incremental $39.5 million related to the Turtle Creek Project, of which $23.8 million related to payments under the APA, (see "Note 15 - Commitments and Contingencies") to the condensed consolidated financial statements, partially offset by lower capitalization of mine development costs at Oaktown and (ii) a $0.4 million decrease in investments in equity method affiliates.
For the nine months ended September 30, 2026, capital expenditures ("Capex") was $91.1 million allocated as follows (in millions):
| Oaktown | $ | 12.4 | |||||||||
| Merom and other power projects | 31.7 | ||||||||||
| Merom - ELG | 7.4 | ||||||||||
| Turtle Creek Project | 39.5 | ||||||||||
| Capex per the condensed consolidated statements of cash flows | $ | 91.1 | |||||||||
We expect our 2026 Capex to modestly increase as compared to our 2025 Capex, excluding any impacts of the Turtle Creek 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 net borrowings of debt of $520.0 million largely attributable to the KLIM Facility, (ii) an increase in cash of $53.8 million from the net proceeds of the January 2026 CMPO, (iii) incremental payments of debt issuance costs of $32.1 million, and (iv) a decrease in cash from incremental lease financing payments of $1.3 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 access the delayed draw term loan commitment under the KLIM facility is subject to conditions precedent including satisfactory commercialization and execution of a construction agreement. Further, we anticipate that if we are able to enter into a Super Priority Revolver as permitted under the KLIM facility that there would be standard market terms and conditions related to the availability of funds. 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 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 replaced the credit agreement with PNC Bank and included a $75.0 million revolving credit facility (the "TCB Revolving Credit Facility") and a $45.0 million delayed draw term loan (the "TCB Delayed Draw Term Loan", and together with the TCB Revolving Credit Facility, the "TCB Credit Facility"). The TCB Credit Facility was used to repay the PNC Bank credit facility and for working capital and general corporate purposes. The TCB Credit Facility was repaid in full and terminated on September 15, 2026 with proceeds of the KLIM Facility.
On September 15, 2026, Hallador Energy Company and its wholly-owned subsidiary, Turtle Creek Gas Holdings, LLC ("Turtle Creek"), each as a co-borrower, jointly and severally liable for all obligations thereunder, entered into a Credit Agreement (the "Credit Agreement") with Kennedy Lewis Investment Management LLC ("KLIM"), acting for certain managed or advised funds and accounts, the other lenders from time to time party thereto, U.S. Bank Trust Company, National Association, as administrative agent, and U.S. Bank National Association, as collateral agent. The Credit Agreement provides for a $600.0 million senior secured term loan facility, with $550.0 million funded at closing and a $50.0 million delayed draw available for 12 months after closing, subject to an agreed draw schedule and funding conditions (the "KLIM Facility"). The KLIM Facility was entered into to repay the TCB Credit Facility and to finance the development and construction of the Turtle Creek Project. See "Note 5 - Debt" to the condensed consolidated financial statements for additional information.
MOIC Premium. Upon repayment in full of the KLIM term loans, whether at maturity, upon acceleration, or in connection with a refinancing or other prepayment, we are required to pay a premium to the extent necessary for each lender to have received total payments and outstanding principal (including PIK interest) equal to at least 1.35 times its funded term commitment, increasing to 1.5 times if the maturity date is extended (the "MOIC Premium"). The MOIC Premium declines as interest is paid or accrues over time, and is largest if the term loans are repaid early. For illustrative purposes, if the term loans had been repaid in full on September 30, 2026, we would have been required to pay a MOIC Premium of approximately $190.6 million. The MOIC Premium is not recorded as a liability as of September 30, 2026. See "Note 5 - Debt." We may pursue a refinancing of the KLIM Facility prior to its scheduled maturity, which would require payment of any MOIC Premium then due. Any such payment could be significant and would require us to use available cash or obtain additional financing, which may not be available on acceptable terms or at all.
See "Item 1. Financial Statements - Note 5 - Debt" to our unaudited condensed consolidated financial statements for additional discussion about our 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 $18.6 million, including $6.6 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 nine months ended September 30, 2026.
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