Hallador Energy Co.: Q2 FY2026 earnings call

What management said about Q2 FY2026, from the documents filed with the SEC on 10 August 2026: press release. Guidance figures: 1 raised, 1 lowered. The quarter’s numbers.

Key takeaways

Revenue slipped and net loss widened: Total revenue was $101.5 million against $102.8 million a year earlier. Net loss was $15.2 million, compared with net income of $8.2 million. Source
Adjusted EBITDA turned negative: Adjusted EBITDA was $(2.9) million, against $3.4 million in the prior-year quarter. Six-month Adjusted EBITDA was $2.6 million, against $22.7 million. Source
Unit 2 downtime coincided with high prices: Limited unplanned Unit 2 downtime coincided with elevated market prices, so Merom bought power at high prices to meet its delivery obligations. Source
Purchased power costs rose to $8.6M: Cost of purchased power was $8.6 million, against $2.2 million a year earlier. Six-month cost was $23.5 million, against $9.0 million. Source
Contracted revenue reached $2.4 billion: Segment-level contracted revenue was $2.4 billion including intercompany coal sales. Consolidated contracted revenue was $1.8 billion. Source
Project budget reduced below $800M: Total project cost is now expected below $800 million, about $1,700 per kW. Management said this is a significant cost advantage over competing new-build capacity. Source
Project moves toward final investment decision: Management said the project moves closer to a final investment decision on a 460 MW peaking project that would expand dispatchable generation. Source
Capital spending rose on outage and project: Capital expenditures were $26.3 million, against $13.1 million, driven by outage reliability upgrades and Turtle Creek spending. Source

“As the equipment, restoration and construction scopes become more defined, the project economics have become even more compelling”
Brent Bilsland, Chairman and Chief Executive Officer

Guidance

Area	Period	Figure	Against last quarter
Turtle Creek project cost Source	Total project cost	below $800 million, or approximately $1,700/kW	Lowered
Turtle Creek commercial operation Source	Target commercial operation	second half of 2028	Raised
Indiana commission approval of contracted sales Source	By November 15, 2026	on or before November 15, 2026

What changed from last quarter

Guidance lowered: Total project cost is now expected below $800 million, about $1,700 per kW. The earlier budget figure is not given in the documents. Source
Guidance raised: Target commercial operation moved to the second half of 2028, which the release describes as expedited. Source
New: The gas project is now formally named Turtle Creek Gas and described as a 460 MW peaking project. The previous release described a proposed 515MW gas plant project. Source
New: The project's interconnection application entered MISO's Expedited Resource Addition Study process on June 2, 2026. Source
New: The company drew $45.0 million under its delayed draw term loan on May 15, 2026, and repaid $8.0 million on its revolving credit facility. Source
New: Brent Bilsland is identified as Chairman and Chief Executive Officer. The previous release identified him as President and Chief Executive Officer. Source

Second quarter results

Revenue slipped and net loss widened: Total revenue was $101.5 million against $102.8 million a year earlier. Net loss was $15.2 million, compared with net income of $8.2 million. Source
Adjusted EBITDA turned negative: Adjusted EBITDA was $(2.9) million, against $3.4 million in the prior-year quarter. Six-month Adjusted EBITDA was $2.6 million, against $22.7 million. Source
Higher costs partly offset by revenue: The company cited higher maintenance and purchased power costs, partly offset by accredited capacity revenue and third-party coal sales. Source
Management sees earning power intact: Management said the second-quarter factors do not, in its view, reflect the earning power of the plant. Source

Power and coal segments

Electric sales down, coal sales up: Electric sales were $59.5 million, against $60.0 million. Third-party coal sales were $40.6 million, against $38.1 million. Other revenue fell to $1.4 million from $4.7 million. Source
Second quarter is the lightest period: Management said the second quarter is traditionally its lightest period, because one Merom unit is taken offline each spring for a planned outage of about 60 days. Source
Unit 2 downtime coincided with high prices: Limited unplanned Unit 2 downtime coincided with elevated market prices, so Merom bought power at high prices to meet its delivery obligations. Source
Unit 1 upgrades completed in outage: During the Unit 1 outage the company completed reliability upgrades. Management said these were designed to address unplanned downtime in recent quarters. Source

“With the scheduled outage behind us and the reliability investments in place, we believe Merom is positioned to run more reliably going forward”
Brent Bilsland, Chairman and Chief Executive Officer

Costs and margins

Purchased power costs rose to $8.6M: Cost of purchased power was $8.6 million, against $2.2 million a year earlier. Six-month cost was $23.5 million, against $9.0 million. Source
Outage maintenance lifted operating costs: Other operating and maintenance costs were $39.1 million, against $29.0 million. The company attributed the increase to the planned outage at Unit 1. Source
Operating result moved to a loss: Loss from operations was $(12.7) million, against income from operations of $11.8 million a year earlier. Source

Contracted sales and demand

Contracted revenue reached $2.4 billion: Segment-level contracted revenue was $2.4 billion including intercompany coal sales. Consolidated contracted revenue was $1.8 billion. Source
Accredited capacity sold through 2040: Contracted revenue covers delivered energy, accredited capacity and third-party coal sales, with accredited capacity commitments extending to 2040. Source
Demand from more counterparties: Management cited demand for accredited capacity and energy from a growing and more varied set of counterparties. Source

“we believe Hallador offers investors a degree of revenue visibility that we believe is among the strongest in the sector”
Brent Bilsland, Chairman and Chief Executive Officer

Turtle Creek gas project

Project budget reduced below $800M: Total project cost is now expected below $800 million, about $1,700 per kW. Management said this is a significant cost advantage over competing new-build capacity. Source
Commercial operation targeted for 2028: Target commercial operation moved to the second half of 2028. Management said this timeline is materially ahead of comparable projects. Source
Turbine disassembly underway on site: A substantial Siemens workforce is disassembling the turbine equipment on site. Management said it is pleased with the progress and the condition of the equipment. Source
Project moves toward final investment decision: Management said the project moves closer to a final investment decision on a 460 MW peaking project that would expand dispatchable generation. Source

Capital, cash and financing

Operating cash flow negative in quarter: Operating cash flow was $(23.9) million for the quarter, against $11.4 million. Six-month operating cash flow was $(3.4) million, against $49.8 million. Source
Capital spending rose on outage and project: Capital expenditures were $26.3 million, against $13.1 million, driven by outage reliability upgrades and Turtle Creek spending. Source
Bank debt rose to $45.0 million: Total bank debt was $45.0 million at June 30, 2026, against no bank debt at March 31, 2026. The company drew $45.0 million on the term loan in May. Source
Liquidity lower than in March: Total liquidity was $84.2 million at quarter-end, against $97.5 million at March 31 and $42.0 million a year earlier. Source
Public offering proceeds in first half: Six-month cash flow includes $53.8 million of net proceeds from a public offering. Shares outstanding rose to 47.1 million from 43.8 million at December 31, 2025. Source
Financing aimed at limiting dilution: Management said it is advancing financing discussions for Turtle Creek, with the aim of minimizing equity dilution. Source

Coming up, as management said on 10 August 2026

Interconnection study results due mid-August: Management expects the ERAS results, including system upgrade costs, in mid-August. Source
Final investment decision targeted for September: Management is targeting a final investment decision and execution of a generator interconnection agreement in September. Source
Turbine shipment scheduled for September: Management said shipment of the turbine equipment remains on schedule for September. Source
More forward sales targeted before year-end: Management said it is working toward additional forward sales before the end of 2026. Source

Risks management discussed

Operational: Unit 2 unplanned downtime during high price periods required power purchases to meet delivery obligations, which magnified the financial impact. Source
Demand: The release notes that revenue from forward sales positions may differ from contracted amounts for several reasons, including unit contingencies. Source
Regulatory: Some contracted forward sales require Indiana Utility Regulatory Commission approval, which the company expects on or before November 15, 2026. Source
Financial: Management lists the interconnection, construction and financing workstreams as principal remaining steps before a final investment decision. Source

Earlier plans management reported on

On track: Management said shipment of the equipment remains on schedule for September. Source
Met: Management said reliability upgrades were completed during the Unit 1 outage to address recent unplanned downtime. Source
Not stated: The prior release expected a meaningful improvement in performance through the year and into peak seasons.
Not stated: The prior release said the agreement is subject to approvals anticipated in the second half of 2026. The current release gives a November 15, 2026 expectation for Indiana approval.

Other quarters

Summarised with AI from the documents the company filed with the SEC. Every point is checked against the filing before it is shown: management’s own words word for word, figures against the line or table row they come from. A point that fails the check is left out. Source opens the filing at that line.

As filed with the SEC

Open the filing on EDGAR

Hallador Reports Q2 2026 Results; Gas Project Budget Reduced Below $800 Million

Turtle Creek COD Expedited to the Second Half of 2028 -
Contracted Forward Sales Reach $2.4 Billion at the Segment Level -
Management to Host Conference Call Today at 5:00 p.m. ET -

TERRE HAUTE, Ind., August 10, 2026 - Hallador Energy Company (Nasdaq: HNRG) (“Hallador” or the “Company”) today reported its financial and operating results for the second quarter ended June 30, 2026. The Company is also providing an update on the continued advancement of its Merom natural gas generation project, now formally named Turtle Creek Gas (“Turtle Creek”), including progress on equipment procurement, financing and interconnection.

“Since our strategic update in June, we have made significant progress across key elements of the Turtle Creek project,” said Brent Bilsland, Chairman and Chief Executive Officer. “We recently completed a site visit to get a firsthand update of the disassembly of the turbine equipment, which is underway with a substantial Siemens workforce on site, and we continue to be pleased with both the progress of the disassembly efforts and the condition of the turbine equipment. Shipment of the equipment remains on schedule for September, and the generator interconnection process is also advancing. As the equipment, restoration and construction scopes become more defined, the project economics have become even more compelling, and we now expect total project cost to be below $800 million, or approximately $1,700/kW - which we believe is a significant cost advantage relative to competing new-build capacity - while moving forward our targeted commercial operation timeframe to the second half of 2028, a timeline we believe is materially ahead of comparable projects. This progress moves us closer to a final investment decision on a 460 MW peaking project that would meaningfully expand and diversify our dispatchable generation platform. At the same time, the market backdrop continues to validate the strategic rationale for that investment. We are seeing robust demand for accredited capacity and energy from a growing and increasingly diverse set of counterparties, and are working towards additional forward sales before the end of the year. With $2.4 billion of revenue already contracted through 2040, and potentially more sales on the way, we believe Hallador offers investors a degree of revenue visibility that we believe is among the strongest in the sector.”

“Operationally, the second quarter is traditionally our lightest period of the year, as we take one of Merom's two units offline each spring for an approximately 60-day scheduled maintenance outage. During this year's outage at Unit 1, we completed major reliability upgrades designed to address the unplanned downtime the unit experienced in recent quarters. Unit 2 performed well over the course of the quarter; however, the limited unplanned downtime it did experience coincided with periods of elevated market prices, which magnified the financial impact by requiring us to purchase power at high prices to meet our delivery obligations. Together, these factors weighed on our second quarter results but do not, in our view, reflect the earning power of the plant. With the scheduled outage behind us and the reliability investments in place, we believe Merom is positioned to run more reliably going forward, and we expect generation volumes to improve sequentially in the third quarter.”

Turtle Creek Update

The project’s interconnection application entered MISO’s Expedited Resource Addition Study (“ERAS”) process on June 2, 2026. Hallador expects to receive the results of that process, including the required system upgrade costs, in mid-August and, following its review, is targeting a final investment decision of the project and execution of a generator interconnection agreement in September. Indications to date from the study process have been encouraging.

In parallel, the Company is finalizing the construction scope and advancing financing discussions as it evaluates the appropriate capital structure for the project, with the objective of financing the project while minimizing equity dilution. Together, the interconnection, construction, and financing workstreams are among the principal remaining steps toward a final investment decision. The Company is now targeting commercial operation in the second half of 2028.

Second Quarter 2026 Highlights

Second quarter results reflected higher maintenance costs associated with the annual planned outage at Merom Unit 1, during which the Company completed significant reliability upgrades, and higher purchased power costs resulting from limited unplanned downtime at Unit 2 that coincided with periods of elevated power prices, requiring the Company to purchase power to meet its delivery obligations. These impacts were partially offset by higher accredited capacity revenue and third-party coal sales.
Total revenue decreased to $101.5 million in the second quarter of 2026 from $102.8 million in the prior year period. The decrease was primarily driven by lower delivered energy sales, partially offset by higher accredited capacity revenue and third-party coal sales.
Net loss was $15.2 million in Q2 2026 compared to net income of $8.2 million in the prior-year period. Adjusted EBITDA was $(2.9) million in the second quarter of 2026 compared to $3.4 million in the prior-year period.
Hallador continued to invest in Merom while positioning its balance sheet to support its strategic priorities.
On May 15, 2026, Hallador drew $45.0 million available under its delayed draw term loan and used a portion of the proceeds to repay $8.0 million on the Company’s revolving credit facility. Total bank debt was $45.0 million at June 30, 2026, compared to no outstanding bank debt at March 31, 2026 and $30.0 million at December 31, 2025.
Total liquidity was $84.2 million at June 30, 2026, compared to $97.5 million at March 31, 2026 and $42.0 million at June 30, 2025.
Capital expenditures were $26.3 million in Q2 2026 compared to $13.1 million in the prior-year period, primarily driven by reliability upgrades completed during the planned outage and expenditures for the Turtle Creek project.
Hallador continues to execute its contracting strategy, increasing long-term revenue visibility and monetizing its dispatchable generation platform.
As of June 30, 2026, Hallador had $1.8 billion of contracted revenue from delivered energy, accredited capacity and third-party coal sales, including accredited capacity commitments extending through 2040. Including intercompany coal sales, total contracted revenue at the segment level was $2.4 billion.

Financial Summary ($ in Millions and Unaudited)

	Q2 2026	Q2 2025
Electric Sales	$59.5	$60.0
Coal Sales - 3 Party	$40.6	$38.1
Other Revenue	$1.4	$4.7
Total Sales and Operating Revenue	$101.5	$102.8
Net Income (Loss)	$(15.2)	$8.2
Operating Cash Flow	$(23.9)	$11.4
Adjusted EBITDA*	$(2.9)	$3.4

* 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		Six Months Ended
	June 30,		June 30,
	2026	2025	2026	2025
ADJUSTED EBITDA	$(2,864)	$3,398	$2,643	$22,708
Stock-based compensation	(1,408)	(475)	(2,543)	(1,559)
Asset retirement obligations accretion	(416)	(437)	(824)	(864)
Other amortization (1)	2,251	13,032	3,202	24,366
Gain (loss) on disposal or abandonment of assets, net	(15)	55	186	76
Loss on extinguishment of debt	-	-	(230)	-
Equity method investment (loss)	(244)	197	(365)	(39)
Other reclassifications	(22)	1,839	(36)	1,600
EBITDA	(2,718)	17,609	2,033	46,288
Interest expense	(3,776)	(3,819)	(7,746)	(7,542)
Income tax (expense) benefit	1,164	-	1,668	-
Depreciation, depletion and amortization	(9,905)	(5,542)	(20,511)	(20,519)
NET INCOME (LOSS)	$(15,235)	$8,248	$(24,556)	$18,227

(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 - 2040	Total
Power
Accredited Capacity
Average daily contracted accredited capacity MW	765	789	768	608	500	500
Average contracted accredited capacity price per MWd	$249	$262	$324	$461	$480	$480
Contracted accredited capacity revenue (in millions)	$34.99	$75.31	$90.95	$102.37	$87.54	$824.78	$1,215.94
Energy
Contracted MWh (in millions)	2.59	3.59	1.92	0.71	-	-	8.81
Average contracted price per MWh	$44.15	$44.64	$45.08	$40.75	$ -	$ -
Contracted revenue (in millions)	$114.35	$160.26	$86.55	$28.93	$ -	$ -	$390.09
Total Accredited Capacity & Energy Revenue (in millions)	$149.34	$235.57	$177.50	$131.30	$87.54	$824.78	$1,606.03
Coal
Priced tons - 3rd party (in millions)	1.37	2.30	0.50	-	-	-	4.17
Avg price per ton - 3rd party	$55.72	$56.80	$59.00	-	-	-
Contracted coal revenue - 3rd party (in millions)	$76.34	$130.64	$29.50	$ -	$ -	$ -	$236.48
TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED	$225.68	$366.21	$207.00	$131.30	$87.54	$824.78	$1,842.51
Priced tons - Intercompany (in millions)	1.87	1.50	2.02	2.02	2.02	-	9.43
Avg price per ton - Intercompany	$51.00	$55.00	$56.00	57.00	58.00	-
Contracted coal revenue - Intercompany (in millions)	$95.37	$82.50	$113.12	$115.14	$117.16	$ -	$523.29
TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT	$321.05	$448.71	$320.12	$246.44	$204.70	$824.78	$2,365.80

* Actual revenue related to forward sales positions may differ materially for various reasons, including unit contingencies, price adjustment features for coal quality and cost escalations, volume optionality provisions, including rollover of unfulfilled coal commitments into future periods, and potential force majeure events. Certain contracted forward sales positions included above are subject to approval by the Indiana Utility Regulatory Commission, which the Company expects on or before November 15, 2026. Forward sales figures in the 2026 column are for the period from July 1, 2026 through December 31, 2026. The table above reflects contracted balances as of June 30, 2026.

Forward-Looking Statements

Forward-looking statements notice

This release contains 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"). 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 such as "expects," "believes," "intends," "anticipates," "plans," "estimates," "guidance," "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, those relating to our ability to participate in the 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) and achieve the expected benefits thereof, the anticipated timing of turbine equipment shipment, project cost expectations and expected cost and timing advantages relative to other projects, our expectations regarding additional forward sales, our ability to finance the Turtle Creek project on anticipated terms, including with little to no equity dilution, 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 current expectations and assumptions and analyses made by Hallador and its management in light of experience and perception of historical trends, current conditions and expected future developments, as well as other factors appropriate under the circumstances that involve various risks and uncertainties that could cause actual results to differ materially from those reflected in the statements. These risks include, but are not limited to, those set forth in Hallador’s annual report on Form 10-K for the year ended December 31, 2025, and other Securities and Exchange Commission filings. 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. Hallador undertakes no obligation to revise or update publicly any forward-looking statements except as required by law.

Conference Call and Webcast

Hallador management will host a conference call today, August 10, 2026, at 5:00 p.m. Eastern time to discuss its financial and operational results, followed by a question-and-answer period.

Date: Monday, August 10, 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.

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. 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

Condensed Consolidated Balance Sheets

(in thousands, except per share data)

	June 30,	December 31,
	2026	2025
ASSETS
Current assets:
Cash and cash equivalents	$28,979	$10,070
Restricted cash	5,950	5,302
Accounts receivable	14,396	13,989
Inventory	47,841	42,534
Parts and supplies	51,326	45,854
Prepaid expenses	1,507	5,638
Total current assets	149,999	123,387
Property, plant and equipment:
Land and mineral rights	69,952	69,952
Buildings and equipment	447,072	421,037
Mine development	102,302	102,302
Construction work in progress	57,955	39,671
Finance lease right-of-use assets	12,591	12,591
Total property, plant and equipment	689,872	645,553
Less - accumulated depreciation, depletion and amortization	(384,551)	(367,775)
Total property, plant and equipment, net	305,321	277,778
Equity method investments	2,284	2,647
Operating lease right-of-use assets	2,734	-
Other noncurrent assets	7,706	4,241
Total assets	$468,044	$408,053
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of bank debt, net	$3,747	$ -
Accounts payable	31,632	12,594
Accrued liabilities and other	33,008	29,254
Current portion of lease financing	3,849	7,411
Contract liabilities - current	136,457	103,343
Total current liabilities	208,693	152,602
Long-term liabilities:
Bank debt, net	39,183	29,678
Long-term lease financing	310	1,338
Deferred income taxes	165	1,833
Asset retirement obligations	16,065	15,241
Contract liabilities - long-term	10,000	45,714
Other	3,296	1,814
Total long-term liabilities	69,019	95,618
Total liabilities	277,712	248,220
Commitments and contingencies (Note 14)
Stockholders' equity:
Preferred stock, $.10 par value, 10,000 shares authorized; none issued	-	-
Common stock, $.01 par value, 100,000 shares authorized; 47,144 and 43,817 issued and outstanding, as of June 30, 2026 and December 31, 2025, respectively	471	438
Additional paid-in capital	257,985	202,963
Retained deficit	(68,124)	(43,568)
Total stockholders’ equity	190,332	159,833
Total liabilities and stockholders’ equity	$468,044	$408,053

Condensed Consolidated Statements of Operations

(in thousands, except per share data)

	Three Months Ended June 30,		Six Months Ended June 30,
	2026	2025	2026	2025
SALES AND OPERATING REVENUES:
Electric sales	$59,509	$59,976	$127,286	$145,919
Coal sales	40,601	38,147	75,681	68,332
Other revenues	1,395	4,702	3,026	6,298
Total sales and operating revenues	101,505	102,825	205,993	220,549
EXPENSES:
Fuel	15,451	15,063	30,414	30,273
Other operating and maintenance costs	39,132	28,955	68,288	57,344
Cost of purchased power	8,633	2,172	23,496	9,012
Utilities	3,960	4,507	9,974	8,659
Labor	28,812	26,799	56,200	53,828
Depreciation, depletion and amortization	9,905	5,542	20,511	20,519
Asset retirement obligations accretion	416	437	824	864
Exploration costs	287	98	371	119
General and administrative	7,552	7,501	14,410	14,326
(Gain) loss on disposal or abandonment of assets, net	15	(55)	(186)	(76)
Total operating expenses	114,163	91,019	224,302	194,868
INCOME (LOSS) FROM OPERATIONS	(12,658)	11,806	(18,309)	25,681
Interest income	279	64	426	127
Interest expense (1)	(3,776)	(3,819)	(7,746)	(7,542)
Loss on extinguishment of debt	-	-	(230)	-
Equity method investment (loss)	(244)	197	(365)	(39)
NET INCOME (LOSS) BEFORE INCOME TAXES	(16,399)	8,248	(26,224)	18,227
INCOME TAX EXPENSE (BENEFIT):
Current	-	-	-	-
Deferred	(1,164)	-	(1,668)	-
Total income tax expense (benefit)	(1,164)	-	(1,668)	-
NET INCOME (LOSS)	$(15,235)	$8,248	$(24,556)	$18,227
NET INCOME (LOSS) PER SHARE:
Basic	$(0.32)	$0.19	$(0.52)	$0.43
Diluted	$(0.32)	$0.19	$(0.52)	$0.42
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic	47,133	42,619	46,831	42,798
Diluted	47,133	43,048	46,831	43,434
(1) Interest Expense:
Interest on bank debt	$978	$1,404	$1,840	$2,898
Other interest	2,270	1,891	5,104	3,623
Amortization of debt issuance costs	528	524	802	1,021
Total interest expense	$3,776	$3,819	$7,746	$7,542

Condensed Consolidated Statements of Cash Flows

(in thousands)

	Six Months Ended June 30,
	2026	2025
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$(24,556)	$18,227
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax (benefit)	(1,668)	-
Equity method investment loss	365	39
Depreciation, depletion and amortization	20,511	20,519
Gain on disposal or abandonment of assets, net	(186)	(76)
Loss on extinguishment of debt	230	-
Amortization of debt issuance costs	802	1,021
Asset retirement obligations accretion	824	864
Cash paid on asset retirement obligation reclamation	(332)	(311)
Stock-based compensation	2,543	1,559
Amortization of contract liabilities	(69,505)	(65,597)
Accretion on contract liabilities	5,104	3,215
Amortization of right-of-use assets	319	-
Other	1,465	284
Change in current assets and liabilities:
Accounts receivable	(407)	(3,304)
Inventory	(5,307)	(6,885)
Parts and supplies	(5,472)	(3,651)
Prepaid expenses	(452)	1,003
Accounts payable and accrued liabilities	10,527	5,062
Contract liabilities	61,801	77,814
Net cash (used in) provided by operating activities	(3,394)	49,783
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(33,941)	(24,737)
Proceeds from sale of equipment	200	162
Investment in equity method investments	-	(322)
Net cash used in investing activities	(33,741)	(24,897)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on bank debt	(79,200)	(44,000)
Borrowings of bank debt	94,200	45,000
Payments on lease financing	(4,631)	(3,421)
Debt issuance costs	(6,189)	(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	(1,441)	(1,918)
Net cash (used in) provided by financing activities	56,692	(4,669)
Increase in cash, cash equivalents, and restricted cash	19,557	20,217
Cash, cash equivalents, and restricted cash, beginning of period	15,372	12,153
Cash, cash equivalents, and restricted cash, end of period	$34,929	$32,370
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH:
Cash and cash equivalents	$28,979	$9,228
Restricted cash	5,950	23,142
	$34,929	$32,370
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$1,435	$2,768
SUPPLEMENTAL NON-CASH FLOW INFORMATION:
Non-cash change in capital expenditures included in accounts payable and prepaid expense	$14,773	$843
Right-of-use asset additions	$2,407	$ -

Contacts
Sean Mansouri, CFA
Elevate IR
(720) 330-2829
HNRG@elevate-ir.com