Hallador Energy posts $4.5M net loss in Q3 2026
Hallador Energy Company reported third-quarter 2026 revenue of $130.3 million, down 11% year over year but up 28% quarter over quarter.
Sentiment and the balance of points
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Form Type
8-K
Rhea-AI Filing Summary
Hallador Energy Company reported third-quarter 2026 revenue of $130.3 million, down 11% year over year but up 28% quarter over quarter. Net loss was $4.5 million, versus $23.9 million net income a year earlier and a $15.2 million loss in Q2; adjusted EBITDA was $17.3 million versus $24.9 million a year earlier. Merom generation rose 77% sequentially to approximately 1.4 million megawatt-hours after a planned maintenance outage.
Hallador took title in October to turbine equipment under its $350 million Turtle Creek asset purchase agreement and deposited the remaining $265 million consideration into escrow, with releases tied to milestones. MISO completed its interconnection study; the interconnection agreement remains unexecuted. Hallador targets a final investment decision before year-end, subject to board approval, definitive agreements and financing, and targets commercial operation in the second half of 2028. A $600 million senior secured construction bridge loan facility, including $550 million funded at closing and a committed $50 million delayed draw tranche, is the largest component of the project’s capital plan; a $75 million revolving credit facility is being finalized. Total debt was $551.9 million at September 30, 2026, versus $45.0 million at June 30, 2026. Contracted revenue was approximately $3.0 billion at the segment level, including intercompany coal sales, as of September 30, 2026, with the October 7 contracts included.
1 point · 0 major0 major · 2 points
How this balance works
Rhea-AI gives every point it takes from this document a weight. Minor counts 1, Moderate 3 and Major 9, so one Major point outweighs several Minor ones. The bar adds up the weights on each side, and when neither side holds more than 65% of the total the balance reads Mixed.
It reads the document as published, with the same rules for every company, and it does not look at what the market expected or at how the stock traded, so a point can be objectively good on a day the stock falls.
Rhea-AI Sentiment measures something else, the tone of the wording.
Positive
- Moderate pointQuarterly revenue rose 28% sequentially to $130.3 million.
Negative
- Moderate pointRevenue fell 11% year over year to $130.3 million.
- Moderate pointNet income was a $4.5 million loss, versus $23.9 million income a year earlier.
Filing Explained
On September 30, 2026, $329.8 million remained restricted, primarily for turbine acquisition and related costs.
Hallador's Turtle Creek project remains pre-FID; its construction borrowing places liens on substantially all company assets, while further project capital remains uncommitted. The
At
8-K Event Classification
2 items: 2.02, 9.01
2 items
Item 2.02
Results of Operations and Financial Condition
Financial
Disclosure of earnings results, typically an earnings press release or preliminary financials.
Item 9.01
Financial Statements and Exhibits
Exhibits
Financial statements, pro forma financial information, or exhibit attachments filed with this report.
Key Figures
Total revenue: $130.3 million
Net loss: $4.5 million
Adjusted EBITDA: $17.3 million
+5 more
8 metrics
Total revenue
$130.3 million
Third quarter 2026
Net loss
$4.5 million
Third quarter 2026
Adjusted EBITDA
$17.3 million
Third quarter 2026
Operating cash flow
$21.8 million used
Third quarter 2026
Total debt
$551.9 million
At September 30, 2026; $45.0 million at June 30, 2026
Total liquidity
$103.2 million
At September 30, 2026
Contracted revenue at the segment level
Approximately $3.0 billion
As of September 30, 2026, including intercompany coal sales and the impacts of the October 7, 2026 contracts
Senior secured construction bridge loan facility
$600 million
Turtle Creek financing; $550 million funded at closing and a committed $50 million delayed draw tranche
Key Terms
final investment decision, accredited capacity, offtake agreements, unit contingent, +1 more
5 terms
final investment decision technical
"targeting a final investment decision before the end of 2026"
A final investment decision is the point at which a person or organization chooses to move forward with a particular project or purchase after reviewing all the necessary information and options. It is like deciding to buy a house after considering all the costs, benefits, and alternatives. This decision is important because it determines whether and when the investment will be made, impacting future financial plans and outcomes.
accredited capacity technical
"accredited capacity commitments extending through 2040"
Accredited capacity describes the role or authority someone holds because a regulator, certifier, or institution has formally approved them to carry out specific duties or access certain information. It matters to investors because that status determines who can make binding decisions, receive confidential disclosures or take part in restricted deals—think of it like having a specialized license that allows certain official actions and access.
offtake agreements financial
"focused on securing long-term offtake agreements"
An offtake agreement is a contract where a buyer agrees to purchase a set amount of a company's future production—such as minerals, energy, or manufactured goods—often before the product is made. For investors, these deals act like a guaranteed customer or advance order that reduces sales risk, helps secure project financing, and makes future revenue more predictable; think of it as a long-term subscription that stabilizes cash flow.
unit contingent technical
"The contract is unit contingent"
A unit contingent is a security (often called a “unit,” which may bundle a share, warrant and/or other instrument) whose issuance, conversion, exercise rights or other effects will only take place if specified conditions or milestones are met. The contingencies can be contractual or regulatory — for example shareholder or regulatory approval, receipt of funds, closing of a related transaction, or achievement of performance milestones — and until those conditions are satisfied the unit’s additional rights or deliverables typically do not exist or are not exercisable. The exact triggers and consequences are defined in the offering or transaction documents, so the practical meaning depends on the contract language rather than a single universal legal rule.
delayed draw term loan tranche financial
"a committed $50 million delayed draw term loan tranche"
Earnings Snapshot
Total revenue: $130.3 million
Third quarter 2026
Total revenue
$130.3 million
Decreased 11% year over year; increased 28% quarter over quarter
Net income (loss)
$4.5 million net loss
Compared with $23.9 million net income in Q3 2025 and a $15.2 million net loss in Q2 2026
Adjusted EBITDA
$17.3 million
Compared with $24.9 million in Q3 2025 and $(2.9) million in Q2 2026
Operating cash flow
$21.8 million used
Compared with $23.2 million provided in Q3 2025
FAQ
AI-generated questions and answers. How Rhea-AI works. Not financial advice.
What were HNRG’s third-quarter 2026 results?
Hallador reported $130.3 million in revenue and a $4.5 million net loss for Q3 2026. Adjusted EBITDA was $17.3 million. Revenue decreased 11% year over year and increased 28% quarter over quarter.
What is the status of HNRG’s Turtle Creek project?
MISO completed its interconnection study, while the interconnection agreement remains unexecuted. Hallador targets a final investment decision before year-end, subject to board approval, definitive agreements and financing, and targets commercial operation in the second half of 2028. The turbines are being transported to the United States for inspection and refurbishment by Siemens.
How is Hallador financing Turtle Creek?
The project’s capital plan includes a $600 million senior secured construction bridge loan facility, with $550 million funded at closing and a committed $50 million delayed draw term loan tranche. The delayed draw tranche remained undrawn at quarter-end. Hallador is also finalizing a $75 million super-priority revolving credit facility.
How much contracted revenue does HNRG report?
Hallador reported $2.5 billion of contracted revenue from delivered energy, accredited capacity and third-party coal sales, and approximately $3.0 billion at the segment level including intercompany coal sales. The totals are as of September 30, 2026, and include the impacts of contracts signed October 7, 2026.
AI-generated analysis. How Rhea-AI works. Not financial advice.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): November 9, 2026
(Exact name of registrant as specified in its charter)
| (State or other jurisdiction of incorporation) | (Commission File Number) | (IRS Employer Identification No.) | ||||||
| (Address, including zip code, of principal executive offices) | ||
Registrant’s telephone number, including area code: (812 ) 299-2800
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) | |||||
| Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) | |||||
| Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) | |||||
| Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) | |||||
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol | Name of each exchange on which registered | ||||||||||||
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Item 2.02 - Results of Operations and Financial Condition
On November 9, 2026, Hallador Energy Company issued a press release announcing its third quarter 2026 financial and operating results. A copy of the press release is attached hereto as Exhibit 99.1 and is incorporated by reference herein.
The information included in this Current Report on Form 8-K, including Exhibit 99.1 hereto, that is furnished pursuant to this Item 2.02 shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section or Sections 11 and 12(a)(2) of the Securities Act of 1933, as amended. In addition, the information included in this Current Report on Form 8-K, including Exhibit 99.1 hereto, that is furnished pursuant to this Item 2.02 shall not be incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing, unless expressly incorporated by specific reference into such filing.
Item 9.01 – Financial Statements and Exhibits
(d)Exhibits
99.1 – Hallador Reports Q3 2026 Results; Turtle Creek Advances Toward Year-End Final Investment Decision
104 – Cover Page Interactive Data File (embedded within the Inline XBRL document)
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| November 9, 2026 | By: | /s/ERIC VAN DEMAN | ||||||
| Eric Van Deman | ||||||||
| Chief Accounting Officer | ||||||||
EXHIBIT 99.1
Hallador Reports Q3 2026 Results; Turtle Creek Advances Toward Year-End Final Investment Decision
- Contracted Forward Sales Increase 26% from Q2’26 to $3.0 billion1 at the Segment Level -
- Management Targets Approximately $1.6 Billion of Value from Turtle Creek Within 24 Months -
TERRE HAUTE, Ind., November 9, 2026 – Hallador Energy Company (Nasdaq: HNRG) (“Hallador” or the “Company”) today reported its financial and operating results for the third quarter ended September 30, 2026. The Company is also providing an update on Turtle Creek Gas (“Turtle Creek”), its approximately 460-megawatt natural gas-fired generation project at the Merom site, which the Company is advancing toward a final investment decision (“FID”) targeted before the end of 2026.
“Our goal at Turtle Creek is to seek to roughly double an $800 million investment into $1.6 billion of value over the next 24 months,” said Brent Bilsland, Chairman and Chief Executive Officer. “We believe the market ascribes little to no value to the project today. Turtle Creek will diversify Hallador's generation into natural gas and make us a multi-fuel independent power producer, which we believe broadens the group of investors who can own our shares and finance our company.”
Hallador holds title to the turbines and generator equipment acquired at a substantial discount due in part to the fact that it was located in the Philippines. The equipment has been exported and is now en route to the United States, giving Hallador a speed-to-market advantage over competing projects.
The Midcontinent Independent System Operator (MISO) has completed the interconnection study, and Hallador is finalizing the engineering and construction agreement and remaining equipment purchase orders. The Company is targeting a final investment decision before year-end and is focused on securing long-term offtake agreements with investment-grade counterparties in early 2027.
Bilsland added, “Offtake contracts are the next step in building the project's value. Our financing plan does not require those contracts to be in place, but we believe long-term contracts are likely to improve the terms on which we can raise additional capital. As we advance toward our targeted commercial operation date in the second half of 2028, our objective is to build value at each development stage with little to no equity dilution.”
Each of the three major Merom offtake agreements signed this year, including the latest agreement in October, priced substantially higher than the one before it, bringing Hallador’s forward sales book to approximately $3.0 billion1, including intercompany coal sales. On a combined capacity and energy basis, the October agreement priced at over $80 per megawatt-hour, the highest in the Company’s forward sales book. These agreements pair creditworthy counterparties with protections that help preserve Hallador’s margins. Contract pricing steps up materially beginning in 2027. The Company is focused on generating more hours at Merom, bringing Turtle Creek online and turning that progress into value for shareholders.
Turtle Creek Update
In October 2026, Hallador took title to the turbine equipment under its $350 million asset purchase agreement with Energy World Corporation Ltd. The turbines have never been operated. The equipment departed the Philippines and is being transported to the United States, where Siemens will inspect it and bring it to current spec before installation, as is standard for relocated turbine equipment. The Company deposited the remaining $265 million of the purchase consideration into escrow, with releases tied to milestones under the agreement.
"MISO notified us that the interconnection study, which ran through MISO’s Expedited Resource Addition Study program, is complete,” said Bilsland. “We are now finalizing the interconnection agreement, which has not yet been executed. We
are finalizing an engineering and construction agreement and purchase orders for the balance of the equipment. Our goal is FID before the end of 2026, and commencement of commercial operation remains targeted for the second half of 2028.”
During the quarter, Hallador entered into a $600 million senior secured construction bridge loan facility2 with a term out option to fund Turtle Creek. This loan facility represents the largest component of the project’s capital plan. The Company is also finalizing a $75 million super-priority revolving credit facility to supplement its liquidity. Hallador continues to evaluate additional financing sources to meet remaining capital requirements with a focus on structures that result in little to no equity dilution.
1 - Total Forward Sales Position as of September 30, 2026, including the impacts of the October 7, 2026 contracts. See Forward Sales Position Table below.
2 - The $600 million facility comprises $550 million funded at closing and a committed $50 million delayed draw term loan tranche, which remained undrawn at quarter-end and is available for 12 months after the closing, subject to an agreed draw schedule and funding conditions.
Third Quarter 2026 Highlights
•Hallador’s third quarter results improved sequentially versus the second quarter, as Merom generation increased 77% to approximately 1.4 million megawatt hours following completion of a planned major maintenance outage in July.
◦While total revenue decreased 11% year-over-year to $130.3 million, primarily due to lower third-party coal sales, total revenue increased 28% quarter-over-quarter owing to higher delivered energy sales.
◦Net loss was $4.5 million in Q3 2026 compared to net income of $23.9 million in the prior-year period and a net loss of $15.2 million in the second quarter of 2026. Adjusted EBITDA was $17.3 million in the third quarter of 2026 compared to $24.9 million in the prior-year period and $(2.9) million in the second quarter of 2026.
•The Company secured new construction financing to fund Turtle Creek development, while strengthening liquidity and continuing capital investment at Merom.
◦Total debt rose to $551.9 million at September 30, 2026, from $45.0 million at June 30, 2026, following the closing of a $600.0 million new senior secured construction bridge loan facility and refinancing of existing debt. The facility comprises $550.0 million funded at closing and a committed $50.0 million delayed draw term loan tranche, which remained undrawn at quarter-end and is available subject to funding conditions. At quarter-end, $329.8 million of the funded proceeds remained in restricted cash, primarily for the turbine acquisition and related costs.
◦Total liquidity was $103.2 million at September 30, 2026, compared to $84.2 million at June 30, 2026 and $46.4 million at September 30, 2025.
◦Capital expenditures were $57.1 million in Q3 2026 compared to $19.5 million in the prior-year period, primarily driven by expenditures for the Turtle Creek project and Merom reliability upgrades completed during the planned outage.
•Hallador continues to execute its contracting strategy, increasing long-term revenue visibility and monetizing its dispatchable generation platform.
◦As of September 30, 2026, and including the impacts of the agreements signed on October 7, 2026, Hallador had $2.5 billion of contracted revenue from delivered energy, accredited capacity and third-party coal sales, with accredited capacity commitments extending through 2040. Including intercompany coal sales, total contracted revenue at the segment level was $3.0 billion.
Financial Summary ($ in Millions and Unaudited)
| Q3 2026 | Q2 2026 | Q3 2025 | |||||||||||||||||||||||||||
| Electric Sales | $ | 92.8 | $ | 59.5 | $ | 93.2 | |||||||||||||||||||||||
| Coal Sales - 3rd Party | $ | 36.1 | $ | 40.6 | $ | 51.3 | |||||||||||||||||||||||
| Other Revenue | $ | 1.3 | $ | 1.4 | $ | 2.1 | |||||||||||||||||||||||
| Total Sales and Operating Revenue | $ | 130.3 | $ | 101.5 | $ | 146.6 | |||||||||||||||||||||||
| Net Income (Loss) | $ | (4.5) | $ | (15.2) | $ | 23.9 | |||||||||||||||||||||||
| Operating Cash Flow | $ | (21.8) | $ | (23.9) | $ | 23.2 | |||||||||||||||||||||||
| Adjusted EBITDA* | $ | 17.3 | $ | (2.9) | $ | 24.9 | |||||||||||||||||||||||
______________________________________________________________________
*Non-GAAP financial measure, defined as EBITDA plus effects of certain subsidiary and equity method investment activity, less other amortization, plus certain operating activities including stock-based compensation, asset retirement obligations accretion, less gain on disposal or abandonment of assets, plus loss on extinguishment of debt and other reclassifications such as special non-recurring project expenses.
Adjusted EBITDA should not be considered an alternative to net income, income from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with GAAP. Our method of computing Adjusted EBITDA may not be the same method used to compute similar measures reported by other companies. Management believes the non-GAAP financial measure, Adjusted EBITDA, is an important measure in analyzing our operations.
Reconciliation of Adjusted EBITDA to Net Income (Loss)
(In $ Thousands and Unaudited)
| Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||||||||||
| September 30, | September 30, | |||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||||||||||||||
| ADJUSTED EBITDA | $ | 17,291 | $ | 24,866 | $ | 19,934 | $ | 47,574 | ||||||||||||||||||||||||||||||
| Stock-based compensation | (1,187) | (585) | (3,730) | (2,144) | ||||||||||||||||||||||||||||||||||
| Asset retirement obligations accretion | (427) | (446) | (1,251) | (1,310) | ||||||||||||||||||||||||||||||||||
| Other amortization (1) | 1,010 | 12,212 | 4,212 | 36,578 | ||||||||||||||||||||||||||||||||||
| Gain (loss) on disposal or abandonment of assets, net | (343) | 2,334 | (157) | 2,410 | ||||||||||||||||||||||||||||||||||
| Loss on extinguishment of debt | (5,717) | — | (5,947) | — | ||||||||||||||||||||||||||||||||||
| Equity method investment (loss) | 358 | (248) | (7) | (287) | ||||||||||||||||||||||||||||||||||
| Other reclassifications | (26) | (180) | (62) | 1,420 | ||||||||||||||||||||||||||||||||||
| EBITDA | 10,959 | 37,953 | 12,992 | 84,241 | ||||||||||||||||||||||||||||||||||
| Interest expense | (6,007) | (4,927) | (13,753) | (12,469) | ||||||||||||||||||||||||||||||||||
| Income tax (expense) benefit | (1,826) | — | (158) | — | ||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | (7,623) | (9,142) | (28,134) | (29,661) | ||||||||||||||||||||||||||||||||||
| NET INCOME (LOSS) | $ | (4,497) | $ | 23,884 | $ | (29,053) | $ | 42,111 | ||||||||||||||||||||||||||||||
(1)Other amortization relates to the non-cash amortization of the Hoosier PPA entered into and parts and supplies inventory acquired in connection with the acquisition of the Merom Power Plant in 2022.
Forward Sales Position - (unaudited)*
| 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 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
1 Total Forward Sales Position as of September 30, 2026, including the impacts of the October 7, 2026 contracts. 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
Forward-Looking Statements
This release, and the statements made by management on the related earnings conference call (the “Call”), contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), which are intended to be covered by the safe harbor provisions of those sections and of the Private Securities Litigation Reform Act of 1995. Statements that are not strictly historical statements constitute forward-looking statements and may often, but not always, be identified by the use of such words as "expects," "believes," "intends," "anticipates," "plans," "estimates," "goal," "objective," "target," "potential," "possible," or "probable" or statements that certain actions, events or results "may," "will," "should," or "could" be taken, occur or be achieved. Forward-looking statements include, without limitation, statements relating to: the development, financing, cost, construction, and timing of Turtle Creek, including the FID we are targeting before the end of 2026, the arrival, inspection, and refurbishment of the turbine equipment and the release of escrowed purchase consideration, the execution of the interconnection agreement with MISO, the engineering and construction agreement, equipment purchase orders, and pipeline arrangements, and commercial operation in the second half of 2028; project cost expectations relating to Turtle Creek and expected cost and timing advantages relative to other projects; our efforts to secure long-term offtake agreements for Turtle Creek, including on the timing, with the counterparties, and at the prices we expect; our financing and capital plans, including the $75 million revolving credit facility, the delayed draw term loan tranche, additional financing sources, refinancing, a potential sale of a partial interest in Turtle Creek, and our objective of little to no equity dilution; our estimates of the potential value of Turtle Creek and our objective to build value at each development stage; our contracted forward sales, including contract pricing, the step-up in contracted prices beginning January 1, 2027, and the operating cash flow we expect from Merom’s contracted sales as legacy prepaid forward sales contracts expire in the second quarter of 2027; the availability, reliability, and operation of Merom; our ability and the ability of our counterparties to obtain regulatory approvals, including approval by the Indiana Utility Regulatory Commission of contracted capacity agreements; our ability to secure agreements in support of the development and construction of planned projects, including the expansion of our Merom Generating Station; and our expectations with respect to potential accelerating demand for accredited capacity. Forward-looking statements are based on management’s current expectations and assumptions and are subject to risks and uncertainties that could cause actual results to differ materially from those reflected in the statements.
Important factors that could cause actual results to differ materially include: (i) our lack of a signed offtake agreement for Turtle Creek, and uncertainty as to the timing, counterparties, and pricing of any agreement; (ii) the execution, timing, and terms of the interconnection agreement, and the cost of interconnection facilities and network upgrades; (iii) our ability to reach an FID, which remains subject to Board approval, definitive agreements, and financing; (iv) delays, cost overruns, or other difficulties in completing Turtle Creek, including the transport, inspection, refurbishment, and delivery of the turbine equipment, the conditions to release of escrowed purchase consideration, the performance of Siemens, our engineering and construction contractor, and other counterparties, permitting, natural gas supply and pipeline capacity, and tariffs, and our ability to achieve commercial operation by the date required under our credit agreement, the failure of which would be an event of default; (v) the fact that we have not secured commitments for the additional capital we will need, the availability and terms of that capital, including the $75 million revolving credit facility, which has not been executed, and the likelihood that financing will involve dilutive equity or equity-linked securities, in which case our objective of little to no equity dilution may not be achieved; (vi) the cost and restrictions of our $600 million senior secured term loan facility, including paid-in-kind interest, a minimum return of 1.35 times the funded amount payable on any repayment (including a refinancing), a minimum unrestricted cash covenant, liens on substantially all of our assets, limits on transfers of cash from Turtle Creek, and cross-default provisions; (vii) whether we pursue or complete any sale of an interest in Turtle Creek, which would be subject to restrictions in our credit agreement and may require prepayment of the facility; (viii) the assumptions underlying our estimates of the potential value of Turtle Creek, including the outcome of contracting, financing, and construction and how the market values contracted cash flows, which moves with interest rates and market conditions; (ix) the availability and reliability of Merom, including forced outages and equipment failures; (x) the terms of our contracted sales, including unit contingencies, volume options, regulatory approvals, and counterparty performance, and the inclusion in our forward sales of intercompany coal sales and management estimates; and (xi) changes in energy, capacity, and commodity prices, demand, competition, and laws, regulations, and trade and tax policy. Our estimates of the potential value of Turtle Creek reflect management’s current assumptions; they are not guidance or a prediction of our share price.
These and other risks are described in the “Risk Factors” section of Hallador’s Annual Report on Form 10-K for the year ended December 31, 2025, as updated by Part II, Item 1A of its Quarterly Report on Form 10-Q for the quarter ended September 30, 2026 filed with the Securities and Exchange Commission (the “SEC”), and in its other SEC filings. The foregoing list of factors is not exhaustive, and the cautionary statements in this release also apply to the forward-looking statements made on the Call, whether or not they are repeated on the Call. You should not place undue reliance on these forward-looking statements. The forward-looking statements in this release speak only as of the date of this release, and those made on the Call speak only as of the date of the Call. Hallador undertakes no obligation to revise or update publicly
any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.
Conference Call and Webcast
Hallador management will host a conference call today, November 9, 2026, at 5:00 p.m. Eastern time to discuss its financial and operational results, followed by a question-and-answer period.
Date: Monday, November 9, 2026
Time: 5:00 p.m. Eastern time
Dial-in registration link: here
Live webcast registration link: here
The conference call will also be broadcast live and available for replay in the investor relations section of the Company’s website at www.halladorenergy.com/news-events/events.
About Hallador Energy Company
Hallador Energy Company (Nasdaq: HNRG) is a vertically-integrated Independent Power Producer (IPP) based in Terre Haute, Indiana. The Company has two core businesses: Hallador Power Company, LLC, which produces electricity and provides accredited capacity at its one-Gigawatt (GW) Merom Generating Station, and Sunrise Coal, LLC, which produces and supplies fuel to the Merom Generating Station and other companies. Hallador is also developing Turtle Creek Gas, a 460 Megawatt (MW) natural gas generation project that will expand and diversify its generation portfolio. To learn more about Hallador, visit the Company’s website at www.halladorenergy.com.
Company Contact
Todd E. Telesz
Chief Financial Officer
TTelesz@halladorenergy.com
Investor Relations Contact
Sean Mansouri, CFA
Elevate IR
(720) 330-2829
HNRG@elevate-ir.com
Hallador Energy Company
Condensed Consolidated Balance Sheets
(in thousands, except per share data)
(unaudited)
| September 30, 2026 | December 31, 2025 | ||||||||||
| ASSETS | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 103,155 | $ | 10,070 | |||||||
| Restricted cash | 329,840 | 5,302 | |||||||||
| Accounts receivable | 23,169 | 13,989 | |||||||||
| Inventory | 42,561 | 42,534 | |||||||||
| Parts and supplies | 52,392 | 45,854 | |||||||||
| Prepaid expenses | 2,149 | 5,638 | |||||||||
| Total current assets | 553,266 | 123,387 | |||||||||
| Property, plant and equipment: | |||||||||||
| Land and mineral rights | 69,952 | 69,952 | |||||||||
| Buildings and equipment | 445,171 | 421,037 | |||||||||
| Mine development | 102,302 | 102,302 | |||||||||
| Construction work in progress | 92,009 | 39,671 | |||||||||
| Finance lease right-of-use assets | 10,987 | 12,591 | |||||||||
| Total property, plant and equipment | 720,421 | 645,553 | |||||||||
| Less - accumulated depreciation, depletion and amortization | (374,584) | (367,775) | |||||||||
| Total property, plant and equipment, net | 345,837 | 277,778 | |||||||||
| Equity method investments | 2,642 | 2,647 | |||||||||
| Operating lease right-of-use assets | 2,525 | — | |||||||||
| Other noncurrent assets | 4,471 | 4,241 | |||||||||
| Total assets | $ | 908,741 | $ | 408,053 | |||||||
| LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||||||
| Current liabilities: | |||||||||||
| Accounts payable | $ | 18,449 | $ | 12,594 | |||||||
| Accrued liabilities and other | 39,166 | 29,254 | |||||||||
| Current portion of lease financing | 2,177 | 7,411 | |||||||||
| Contract liabilities - current | 103,730 | 103,343 | |||||||||
| Total current liabilities | 163,522 | 152,602 | |||||||||
| Long-term liabilities: | |||||||||||
| Debt, net | 525,965 | 29,678 | |||||||||
| Deferred income taxes | 1,991 | 1,833 | |||||||||
| Asset retirement obligations | 16,492 | 15,241 | |||||||||
| Contract liabilities - long-term | 10,000 | 45,714 | |||||||||
| Other | 3,759 | 3,152 | |||||||||
| Total long-term liabilities | 558,207 | 95,618 | |||||||||
| Total liabilities | 721,729 | 248,220 | |||||||||
| Commitments and contingencies (Note 15) | |||||||||||
| Stockholders' equity: | |||||||||||
| Preferred stock, $.10 par value, 10,000 shares authorized; none issued | — | — | |||||||||
| Common stock, $.01 par value, 100,000 shares authorized; 47,147 and 43,817 issued and outstanding, as of September 30, 2026 and December 31, 2025, respectively | 471 | 438 | |||||||||
| Additional paid-in capital | 259,162 | 202,963 | |||||||||
| Retained deficit | (72,621) | (43,568) | |||||||||
| Total stockholders’ equity | 187,012 | 159,833 | |||||||||
| Total liabilities and stockholders’ equity | $ | 908,741 | $ | 408,053 | |||||||
See accompanying notes to the condensed consolidated financial statements.
Hallador Energy Company
Condensed Consolidated Statements of Operations
(in thousands, except per share data)
(unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| SALES AND OPERATING REVENUES: | |||||||||||||||||||||||
| Electric sales | $ | 92,846 | $ | 93,235 | $ | 220,132 | $ | 239,154 | |||||||||||||||
| Coal sales | 36,128 | 51,256 | 111,809 | 119,588 | |||||||||||||||||||
| Other revenues | 1,276 | 2,066 | 4,302 | 8,364 | |||||||||||||||||||
| Total sales and operating revenues | 130,250 | 146,557 | 336,243 | 367,106 | |||||||||||||||||||
| EXPENSES: | |||||||||||||||||||||||
| Fuel | 28,764 | 27,119 | 59,178 | 57,392 | |||||||||||||||||||
| Other operating and maintenance costs | 31,547 | 44,415 | 99,835 | 101,759 | |||||||||||||||||||
| Cost of purchased power | 11,103 | 2,074 | 34,599 | 11,086 | |||||||||||||||||||
| Utilities | 5,108 | 4,543 | 15,082 | 13,202 | |||||||||||||||||||
| Labor | 30,488 | 27,574 | 86,688 | 81,402 | |||||||||||||||||||
| Depreciation, depletion and amortization | 7,623 | 9,142 | 28,134 | 29,661 | |||||||||||||||||||
| Asset retirement obligations accretion | 427 | 446 | 1,251 | 1,310 | |||||||||||||||||||
| Exploration costs | 36 | 38 | 407 | 157 | |||||||||||||||||||
| General and administrative | 6,971 | 4,770 | 21,381 | 19,096 | |||||||||||||||||||
| (Gain) loss on disposal or abandonment of assets, net | 343 | (2,334) | 157 | (2,410) | |||||||||||||||||||
| Total operating expenses | 122,410 | 117,787 | 346,712 | 312,655 | |||||||||||||||||||
| INCOME (LOSS) FROM OPERATIONS | 7,840 | 28,770 | (10,469) | 54,451 | |||||||||||||||||||
| Interest income | 855 | 289 | 1,281 | 416 | |||||||||||||||||||
| Interest expense (1) | (6,007) | (4,927) | (13,753) | (12,469) | |||||||||||||||||||
| Loss on extinguishment of debt | (5,717) | — | (5,947) | — | |||||||||||||||||||
| Equity method investment (loss) | 358 | (248) | (7) | (287) | |||||||||||||||||||
| NET INCOME (LOSS) BEFORE INCOME TAXES | (2,671) | 23,884 | (28,895) | 42,111 | |||||||||||||||||||
| INCOME TAX EXPENSE (BENEFIT): | |||||||||||||||||||||||
| Current | — | — | — | — | |||||||||||||||||||
| Deferred | 1,826 | — | 158 | — | |||||||||||||||||||
| Total income tax expense (benefit) | 1,826 | — | 158 | — | |||||||||||||||||||
| NET INCOME (LOSS) | $ | (4,497) | $ | 23,884 | $ | (29,053) | $ | 42,111 | |||||||||||||||
| NET INCOME (LOSS) PER SHARE: | |||||||||||||||||||||||
| Basic | $ | (0.10) | $ | 0.56 | $ | (0.62) | $ | 0.98 | |||||||||||||||
| Diluted | $ | (0.10) | $ | 0.55 | $ | (0.62) | $ | 0.97 | |||||||||||||||
| WEIGHTED AVERAGE SHARES OUTSTANDING | |||||||||||||||||||||||
| Basic | 47,145 | 43,007 | 46,937 | 42,869 | |||||||||||||||||||
| Diluted | 47,145 | 43,434 | 46,937 | 43,287 | |||||||||||||||||||
| (1) Interest Expense: | |||||||||||||||||||||||
| Interest on debt | $ | 3,408 | $ | 1,763 | $ | 5,249 | $ | 4,661 | |||||||||||||||
| Other interest | 1,923 | 2,585 | 7,027 | 6,208 | |||||||||||||||||||
| Amortization of debt issuance costs | 676 | 579 | 1,478 | 1,600 | |||||||||||||||||||
| Total interest expense | $ | 6,007 | $ | 4,927 | $ | 13,753 | $ | 12,469 | |||||||||||||||
See accompanying notes to the condensed consolidated financial statements.
Hallador Energy Company
Condensed Consolidated Statements of Cash Flows
(in thousands)
(unaudited)
| Nine Months Ended September 30, | |||||||||||
| 2026 | 2025 | ||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: | |||||||||||
| Net income (loss) | $ | (29,053) | $ | 42,111 | |||||||
| Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities: | |||||||||||
| Deferred income tax | 158 | — | |||||||||
| Equity method investment loss | 7 | 287 | |||||||||
| Depreciation, depletion and amortization | 28,134 | 29,661 | |||||||||
| Loss (gain) on disposal or abandonment of assets, net | 157 | (2,410) | |||||||||
| Loss on extinguishment of debt | 5,947 | — | |||||||||
| Amortization of debt issuance costs | 1,478 | 1,600 | |||||||||
| Asset retirement obligations accretion | 1,251 | 1,310 | |||||||||
| Paid-in-kind interest | 1,924 | — | |||||||||
| Cash paid on asset retirement obligation reclamation | (452) | (455) | |||||||||
| Stock-based compensation | 3,730 | 2,144 | |||||||||
| Amortization of contract liabilities | (86,806) | (82,639) | |||||||||
| Accretion on contract liabilities | 7,027 | 5,659 | |||||||||
| Amortization of right-of-use assets | 527 | — | |||||||||
| Other | 934 | 274 | |||||||||
| Change in current assets and liabilities: | |||||||||||
| Accounts receivable | (9,180) | (9,325) | |||||||||
| Inventory | (27) | 8,679 | |||||||||
| Parts and supplies | (6,538) | (4,898) | |||||||||
| Prepaid expenses | (1,618) | 1,190 | |||||||||
| Accounts payable and accrued liabilities | 12,803 | 1,923 | |||||||||
| Contract liabilities | 44,453 | 77,867 | |||||||||
| Net cash (used in) provided by operating activities | (25,144) | 72,978 | |||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||
| Capital expenditures | (91,080) | (44,277) | |||||||||
| Proceeds from sale of equipment | 200 | 2,891 | |||||||||
| Investment in equity method investments | — | (394) | |||||||||
| Net cash used in investing activities | (90,880) | (41,780) | |||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||
| Payments on debt | (79,200) | (63,000) | |||||||||
| Borrowings of debt | 599,200 | 63,000 | |||||||||
| Payments on lease financing | (6,474) | (5,187) | |||||||||
| Debt issuance costs | (32,381) | (330) | |||||||||
| Proceeds from ATM offering, net of issuance costs | 189 | — | |||||||||
| Proceeds from public offering, net of issuance costs | 53,764 | — | |||||||||
| Taxes paid on vesting of RSUs | (1,451) | (2,352) | |||||||||
| Net cash (used in) provided by financing activities | 533,647 | (7,869) | |||||||||
| Increase in cash, cash equivalents, and restricted cash | 417,623 | 23,329 | |||||||||
| Cash, cash equivalents, and restricted cash, beginning of period | 15,372 | 12,153 | |||||||||
| Cash, cash equivalents, and restricted cash, end of period | $ | 432,995 | $ | 35,482 | |||||||
| CASH, CASH EQUIVALENTS, AND RESTRICTED CASH: | |||||||||||
| Cash and cash equivalents | $ | 103,155 | $ | 12,663 | |||||||
| Restricted cash | 329,840 | 22,819 | |||||||||
| $ | 432,995 | $ | 35,482 | ||||||||
| SUPPLEMENTAL CASH FLOW INFORMATION: | |||||||||||
| Cash paid for interest | $ | 3,296 | $ | 4,718 | |||||||
| SUPPLEMENTAL NON-CASH FLOW INFORMATION: | |||||||||||
| Non-cash change in capital expenditures included in accounts payable and prepaid expense | $ | 6,116 | $ | (5,855) | |||||||
| Repayment of TCB Credit Facility directly by lenders from KLIM proceeds | $ | 100,200 | $ | — | |||||||
| PIK interest | $ | 1,924 | $ | — | |||||||
| Right-of-use asset additions | $ | 2,407 | $ | — | |||||||
See accompanying notes to the condensed consolidated financial statements.