Hallador Reports Q3 2026 Results; Turtle Creek Advances Toward Year-End Final Investment Decision

Merom generation rose 77% sequentially after maintenance, while operating cash flow remained negative.

Rhea-AI Summary

Hallador Energy (Nasdaq: HNRG) reported a third-quarter net loss of $4.5 million while advancing its Turtle Creek gas-generation project. Revenue was $130.3 million, down 11% year over year but up 28% sequentially. The loss compared with $23.9 million of prior-year profit and a $15.2 million second-quarter loss.

Hallador targets a final investment decision on the approximately 460-megawatt Turtle Creek project before year-end 2026 and commercial operation in the second half of 2028. It took title to turbine equipment and secured a $600 million construction bridge facility; debt reached $551.9 million. The interconnection study is complete, but the agreement remains unsigned. Forward sales, including October 7 contracts, reached approximately $3.0 billion including intercompany coal sales, up 26% from Q2; consolidated contracted revenue was $2,477.89 million. Capacity commitments extend through 2040.

11 points · 1 major

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1 major · 20 points

Hollow bars mark forward-looking points. How the balance works

Positive

• Major point$600 million construction bridge facility secured for Turtle Creek, including $550 million funded at closing. 1.3× market cap
• Moderate pointMerom generation rose 77% sequentially to approximately 1.4 million megawatt-hours following the planned maintenance outage.
• Moderate pointSegment forward sales rose 26% from Q2 to approximately $3.0 billion, including intercompany sales and October 7 contracts. 6.3× market cap
• Moderate point. Forward-looking: it has not happened yet and may not happen.Contract pricing steps up beginning in 2027, with accredited capacity commitments extending through 2040.
• Moderate pointLiquidity reached $103.2 million, versus $84.2 million at June 30 and $46.4 million a year earlier.
• Moderate point. Forward-looking: it has not happened yet and may not happen.Approximately 460-megawatt Turtle Creek project targets year-end 2026 investment approval and second-half 2028 commercial operation.
• Moderate point. Forward-looking: it has not happened yet and may not happen.Management targets approximately $1.6 billion of Turtle Creek value from an $800 million investment within 24 months.
• Moderate point. Forward-looking: it has not happened yet and may not happen.Long-term Turtle Creek offtake agreements with investment-grade counterparties are targeted for early 2027.
• Moderate point$75 million revolving credit facility is being finalized to supplement liquidity. 16% of market cap

2 minor points

• Minor pointOctober Merom agreement pricing exceeded $80 per megawatt-hour on a combined capacity and energy basis.
• Minor pointTurtle Creek turbine title acquired; equipment is en route to the United States, and the interconnection study is complete.

Negative

• Major point$350 million turbine purchase agreement included $265 million deposited into escrow, with releases tied to milestones. 74% of market cap
• Moderate pointQ3 revenue fell 11% year over year to $130.3 million, despite rising 28% sequentially.
• Moderate pointQ3 net loss was $4.5 million, versus $23.9 million prior-year profit and $15.2 million sequential loss.
• Moderate pointQ3 adjusted EBITDA was $17.3 million, versus $24.9 million a year earlier and negative $2.9 million sequentially.
• Moderate pointQ3 operating cash outflow was $21.8 million, versus $23.2 million prior-year inflow and $23.9 million sequential outflow.
• Moderate pointQ3 capital expenditures rose to $57.1 million, from $19.5 million a year earlier.
• Moderate pointTurtle Creek interconnection agreement remains unsigned; construction agreement and remaining equipment orders are being finalized.
• Moderate pointRemaining Turtle Creek capital requirements need additional financing; Hallador is evaluating sources targeting little to no equity dilution.

12 minor points

• Minor pointThird-party coal sales fell to $36.1 million, from $51.3 million a year earlier and $40.6 million sequentially.
• Minor pointElectric sales were $92.8 million, versus $93.2 million a year earlier and $59.5 million sequentially.
• Minor pointOther revenue declined to $1.3 million, from $2.1 million a year earlier and $1.4 million sequentially.
• Minor pointTotal debt rose to $551.9 million at September 30, from $45.0 million at June 30.
• Minor point$329.8 million of funded proceeds remained restricted at quarter-end, primarily for turbine acquisition and related costs.
• Minor point$50 million delayed loan draw remains subject to funding conditions and an agreed draw schedule.
• Minor pointCertain forward sales require Indiana Utility Regulatory Commission approval.
• Minor pointOctober energy contract permits zero base volume for up to 90 days annually and depends on unit operation.
• Minor pointNine-month net loss was $29.053 million, versus $42.111 million net income a year earlier.
• Minor pointNine-month adjusted EBITDA fell to $19.934 million, from $47.574 million a year earlier.
• Minor pointQ3 debt-extinguishment loss was $5.717 million; the nine-month loss was $5.947 million.
• Minor pointQ3 interest expense increased to $6.007 million, from $4.927 million a year earlier.

Key Figures

Total revenue: $130.3 million Net loss: $4.5 million Adjusted EBITDA: $17.3 million +5 more

Total revenue

$130.3 million

Q3 2026; down 11% year-over-year and up 28% quarter-over-quarter

Net loss

$4.5 million

Q3 2026; compared with $23.9 million net income in Q3 2025

Adjusted EBITDA

$17.3 million

Q3 2026; compared with $24.9 million in Q3 2025

Merom generation

Approximately 1.4 million megawatt hours

Q3 2026; increased 77% from Q2 2026

Segment-level forward sales

$3.0 billion

Up 26% from Q2 2026; includes intercompany coal sales

October agreement price

Over $80 per megawatt-hour

Combined capacity and energy basis; highest in the Company's forward sales book

Construction bridge loan facility

$600 million

During the quarter, entered into facility to fund Turtle Creek

Targeted final investment decision

Before the end of 2026

Turtle Creek project milestone

Previous Earnings Reports

2 past events · Latest: Aug 10

Same Type 2 events

1. Aug 10

   Q2 earnings

   24h Move

   -1.5%

   Quarterly revenue was $101.5 million with a $15.2 million net loss.

2. Nov 10

   Q3 earnings

   24h Move

   +19.0%

   Q3 2025 reported $23.9 million net income and $24.9 million adjusted EBITDA.

24h Move is the share-price change in the day after each event; other market factors may also have contributed.

Key Terms

final investment decision, offtake agreements, senior secured construction bridge loan facility

3 terms

final investment decision technical

"advancing toward a final investment decision (“FID”) targeted 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.

offtake agreements financial

"focused on securing long-term offtake agreements with investment-grade counterparties in early 2027"

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.

senior secured construction bridge loan facility financial

"entered into a $600 million senior secured construction bridge loan facility"

A short-term loan facility used to fund construction projects that is senior in the borrower’s debt priority and secured by project assets or other collateral. “Senior” means this debt ranks ahead of other creditors for repayment; “secured” means the lender holds liens or pledges on the project’s assets or revenue; and “bridge” means the loan is intended as interim financing to cover costs until the project is finished or permanent long-term financing is arranged. Such facilities typically have shorter maturities, higher interest or fees than long-term debt, and contractual covenants tied to construction milestones and repayment sources.

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– 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., Nov. 09, 2026 (GLOBE NEWSWIRE) -- 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. 1 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. 2 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.

FAQ

AI-generated questions and answers. How Rhea-AI works. Not financial advice.

When does Hallador expect a Turtle Creek investment decision and commercial operation?

Hallador targets a final investment decision before the end of 2026 and commercial operation in the second half of 2028. The approximately 460-megawatt natural gas-fired project is at the Merom site.

How did Hallador perform in the third quarter of 2026?

Hallador reported $130.3 million in revenue and a $4.5 million net loss. Revenue decreased 11% year over year but increased 28% from the second quarter. Adjusted EBITDA, a non-GAAP earnings measure, was $17.3 million, compared with $24.9 million a year earlier and negative $2.9 million in the second quarter.

What limits the energy revenue in Hallador's October 7 contract?

The October 7 energy contract has an annual average base quantity of 200 MW, but quantities fall proportionately when Merom units do not generate above a specified threshold. The counterparty can also reduce the base quantity to zero for a maximum of 90 days per year. Portions of the forward-sales table use estimated energy quantities and revenue.

What work remains on Hallador's acquired Turtle Creek turbine equipment?

Siemens will inspect the equipment and bring it to current specifications in the United States before installation. The turbines have never been operated. Hallador has taken title, and the equipment has departed the Philippines.

Does Hallador need Turtle Creek offtake contracts before financing the project?

Hallador says its financing plan does not require offtake contracts to be in place, although it believes long-term contracts are likely to improve additional capital-raising terms. The company is targeting agreements with investment-grade counterparties in early 2027.