Open the filing on EDGARHallador Reports Q3 2026 Results; Turtle Creek Advances Toward Year-End Final Investment Decision
- Contracted Forward Sales Increase 26% from Q2’26 to $3.0 billion 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 billion, 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 facility 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 |
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.
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.
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
Forward-looking statements notice
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
Condensed Consolidated Balance Sheets
(in thousands, except per share data)
| 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 |
Condensed Consolidated Statements of Operations
(in thousands, except per share data)
| 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 | |
Condensed Consolidated Statements of Cash Flows
(in thousands)
| 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 | | $ - | |
Contacts
Sean Mansouri, CFA
Elevate IR
(720) 330-2829
HNRG@elevate-ir.com