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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2025

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number:001-34743

HALLADOR ENERGY COMPANY

(www.halladorenergy.com)


Colorado	84-1014610
(State of incorporation)	(IRS Employer Identification No.)

1183 East Canvasback Drive, Terre Haute, Indiana	47802
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: 812.299.2800

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol	Name of each exchange on which registered
Common Shares, $.01 par value	HNRG	Nasdaq

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulations S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer ☐		Accelerated filer ☑
Non-accelerated filer ☐		Smaller reporting company ☑
		Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

As of November 3, 2025, we had 43,825,006 shares of common stock outstanding.

Table of Contents

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION	1

ITEM 1. FINANCIAL STATEMENTS (Unaudited)	1

Condensed Consolidated Balance Sheets	1

Condensed Consolidated Statements of Operations	2

Condensed Consolidated Statements of Cash Flows	3

Condensed Consolidated Statements of Stockholders’ Equity	4

Notes to Condensed Consolidated Financial Statements	5

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	21

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	34

ITEM 4. CONTROLS AND PROCEDURES	34

PART II - OTHER INFORMATION	36

ITEM 1A. RISK FACTORS	36

ITEM 4. MINE SAFETY DISCLOSURES	36

ITEM 6. EXHIBITS	37

SIGNATURES	38

Table of Contents

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Hallador Energy Company

Condensed Consolidated Balance Sheets

(in thousands, except per share data)

(unaudited)


	September 30,		December 31,
	2025		2024
ASSETS
Current assets:
Cash and cash equivalents	$	12,663	$	7,232
Restricted cash		22,819		4,921
Accounts receivable		24,763		15,438
Inventory		28,006		36,685
Parts and supplies		44,002		39,104
Prepaid expenses		4,293		1,478
Total current assets		136,546		104,858
Property, plant and equipment:
Land and mineral rights		69,961		70,307
Buildings and equipment		454,040		429,857
Mine development		99,852		92,458
Finance lease right-of-use assets		13,034		13,034
Total property, plant and equipment		636,887		605,656
Less - accumulated depreciation, depletion and amortization		(370,903)		(347,952)
Total property, plant and equipment, net		265,984		257,704
Equity method investments		2,713		2,607
Other assets		4,218		3,951
Total assets	$	409,461	$	369,120

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of bank debt, net	$	42,698	$	4,095
Accounts payable and accrued liabilities		44,010		44,298
Current portion of lease financing		7,395		6,912
Contract liabilities - current		113,244		97,598
Total current liabilities		207,347		152,903
Long-term liabilities:
Bank debt, net		—		37,394
Long-term lease financing		3,140		8,749
Asset retirement obligations		16,268		14,957
Contract liabilities - long-term		34,362		49,121
Other		2,156		1,711
Total long-term liabilities		55,926		111,932
Total liabilities		263,273		264,835
Commitments and contingencies (Note 16)
Stockholders' equity:
Preferred stock, $.10 par value, 10,000 shares authorized; none issued		—		—
Common stock, $.01 par value, 100,000 shares authorized; 42,978 and 42,621 issued and outstanding, as of September 30, 2025 and December 31, 2024, respectively		430		426
Additional paid-in capital		189,086		189,298
Retained deficit		(43,328)		(85,439)
Total stockholders’ equity		146,188		104,285
Total liabilities and stockholders’ equity	$	409,461	$	369,120

See accompanying notes to the condensed consolidated financial statements.

Table of Contents

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,
	2025		2024		2025		2024
SALES AND OPERATING REVENUES:
Electric sales	$	93,235	$	72,116	$	239,154	$	192,996
Coal sales		51,256		31,662		119,588		114,093
Other revenues		2,355		1,377		8,780		3,685
Total sales and operating revenues		146,846		105,155		367,522		310,774
EXPENSES:
Fuel		27,119		13,755		57,392		34,684
Other operating and maintenance costs		44,415		32,741		101,759		103,704
Cost of purchased power		2,074		3,149		11,086		7,694
Utilities		4,543		3,586		13,202		12,090
Labor		27,574		26,721		81,402		88,444
Depreciation, depletion and amortization		9,142		13,838		29,661		42,930
Asset retirement obligations accretion		446		410		1,310		1,208
Exploration costs		38		62		157		179
General and administrative		4,770		6,471		19,096		20,218
Gain on disposal or abandonment of assets, net		(2,334)		(290)		(2,410)		(536)
Total operating expenses		117,787		100,443		312,655		310,615

INCOME FROM OPERATIONS		29,059		4,712		54,867		159

Interest expense (1)		(4,927)		(2,692)		(12,469)		(10,364)
Loss on extinguishment of debt		—		—		—		(2,790)
Equity method investment (loss)		(248)		(234)		(287)		(740)
NET INCOME (LOSS) BEFORE INCOME TAXES		23,884		1,786		42,111		(13,735)

INCOME TAX EXPENSE (BENEFIT):
Current		—		—		—		—
Deferred		—		232		—		(3,389)
Total income tax expense (benefit)		—		232		—		(3,389)

NET INCOME (LOSS)	$	23,884	$	1,554	$	42,111	$	(10,346)

NET INCOME (LOSS) PER SHARE:
Basic	$	0.56	$	0.04	$	0.98	$	(0.27)
Diluted	$	0.55	$	0.04	$	0.97	$	(0.27)

WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		43,007		42,598		42,869		38,455
Diluted		43,434		43,018		43,287		38,455

(1) Interest Expense:
Interest on bank debt	$	1,763	$	2,073	$	4,661	$	7,657
Other interest		2,585		181		6,208		1,456
Amortization of debt issuance costs		579		438		1,600		1,251
Total interest expense	$	4,927	$	2,692	$	12,469	$	10,364

See accompanying notes to the condensed consolidated financial statements.

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Hallador Energy Company

Condensed Consolidated Statements of Cash Flows

(in thousands)

(unaudited)


	Nine Months Ended September 30,
	2025		2024
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	42,111	$	(10,346)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax (benefit)		—		(3,389)
Equity method investment loss		287		740
Depreciation, depletion and amortization		29,661		42,930
Loss on extinguishment of debt		—		2,790
Gain on disposal or abandonment of assets, net		(2,410)		(536)
Amortization of debt issuance costs		1,600		1,251
Asset retirement obligations accretion		1,310		1,208
Cash paid on asset retirement obligation reclamation		(455)		(820)
Stock-based compensation		2,144		3,320
Amortization of contract liabilities		(82,639)		(59,236)
Accretion on contract liabilities		5,659		—
Other		274		1,352
Change in current assets and liabilities:
Accounts receivable		(9,325)		8,029
Inventory		8,679		(8,002)
Parts and supplies		(4,898)		(786)
Prepaid expenses		1,190		(1,098)
Accounts payable and accrued liabilities		1,923		(7,715)
Contract liabilities		77,867		57,293
Net cash provided by operating activities		72,978		26,985
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(44,277)		(39,606)
Proceeds from sale of equipment		2,891		3,373
Investment in equity method investments		(394)		—
Net cash used in investing activities		(41,780)		(36,233)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on bank debt		(63,000)		(86,500)
Borrowings of bank debt		63,000		65,000
Payments on lease financing		(5,187)		(4,105)
Proceeds from sale and leaseback arrangement		—		3,783
Issuance of related party notes payable		—		5,000
Payments on related party notes payable		—		(5,000)
Debt issuance costs		(330)		(654)
ATM offering		—		34,515
Taxes paid on vesting of RSUs		(2,352)		(273)
Net cash (used in) provided by financing activities		(7,869)		11,766
Increase in cash, cash equivalents, and restricted cash		23,329		2,518
Cash, cash equivalents, and restricted cash, beginning of period		12,153		7,123
Cash, cash equivalents, and restricted cash, end of period	$	35,482	$	9,641
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH:
Cash and cash equivalents	$	12,663	$	3,829
Restricted cash		22,819		5,812
	$	35,482	$	9,641
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	4,718	$	8,679
SUPPLEMENTAL NON-CASH FLOW INFORMATION:
Change in capital expenditures included in accounts payable and prepaid expense	$	(5,855)	$	(7,825)
Stock issued on redemption of convertible notes and interest	$	—	$	22,993

See accompanying notes to the condensed consolidated financial statements.

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Hallador Energy Company

Condensed Consolidated Statements of Stockholders’ Equity

(in thousands)

(unaudited)


				Additional				Total
	Common Stock Issued			Paid-in		Retained		Stockholders’
	Shares	Amount		Capital		Deficit		Equity
Balance, June 30, 2025	42,978	$	430	$	188,935	$	(67,212)	$	122,153
Stock-based compensation	—		—		585		—		585
Stock issued on vesting of RSUs	64		1		(1)		—		—
Taxes paid on vesting of RSUs	(28)		(1)		(433)		—		(434)
Net Income	—		—		—		23,884		23,884
Balance, September 30, 2025	43,014	$	430	$	189,086	$	(43,328)	$	146,188

Balance, December 31, 2024	42,621	$	426	$	189,298	$	(85,439)	$	104,285
Stock-based compensation	—		—		2,144		—		2,144
Stock issued on vesting of RSUs	577		6		(6)		—		—
Taxes paid on vesting of RSUs	(184)		(2)		(2,350)		—		(2,352)
Net Income	—		—		—		42,111		42,111
Balance, September 30, 2025	43,014	$	430	$	189,086	$	(43,328)	$	146,188


				Additional				Total
	Common Stock Issued			Paid-in		Retained		Stockholders’
	Shares	Amount		Capital		Earnings		Equity
Balance, June 30, 2024	42,599	$	426	$	186,945	$	128,799	$	316,170
Stock-based compensation	—		—		1,073		—		1,073
Net income	—		—		—		1,554		1,554
Balance, September 30, 2024	42,599	$	426	$	188,018	$	130,353	$	318,797

Balance, December 31, 2023	34,052	$	341	$	127,548	$	140,699	$	268,588
Stock-based compensation	—		—		3,320		—		3,320
Stock issued on vesting of RSUs	379		4		(4)		—		—
Taxes paid on vesting of RSUs	(159)		(2)		(271)		—		(273)
Stock issued on redemption of convertible notes	3,672		36		22,957		—		22,993
Stock issued in ATM offering	4,655		47		34,468		—		34,515
Net loss	—		—		—		(10,346)		(10,346)
Balance, September 30, 2024	42,599	$	426	$	188,018	$	130,353	$	318,797

See accompanying notes to the condensed consolidated financial statements.

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Hallador Energy Company

Notes to Condensed Consolidated Financial Statements

(unaudited)

(1)	GENERAL BUSINESS

The condensed consolidated financial statements include the accounts of Hallador Energy Company (hereinafter known as “we, us, or our”) and its wholly owned subsidiaries Hallador Power Company, LLC (“Hallador Power”), Sunrise Coal, LLC (“Sunrise”), and Hourglass Sands, LLC (“Hourglass”), as well as Hallador Power and Sunrise’s wholly owned subsidiaries.

Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The Chief Operating Decision Maker (“CODM”), who is the Company’s Chief Executive Officer, reviews and assesses operating performance measures related to our Electric Operations and our Coal Operations segments.

In addition to these reportable segments, the Company has a “Corporate and Other and Eliminations” category, which is not significant enough, on a stand-alone basis, to be considered an operating segment. Corporate and Other and Eliminations primarily consist of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, LLC (“Sunrise Energy”), a private gas exploration company with operations in Indiana and Oaktown Gas, LLC, which we account for using the equity method.

The Electric Operations reportable segment includes electric power generation facilities of the Merom Power Plant (“Merom”).

The Coal Operations reportable segment includes our currently operating underground mining complex Oaktown 1. We have other mining complexes and locations which were idled during the year ended December 31, 2024.

All significant intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to the Company’s prior period condensed consolidated financial information to conform to the current period presentation. These presentation changes did not impact the Company’s condensed consolidated net income (loss), consolidated cash flows, total assets, total liabilities or total stockholders’ equity.

The interim financial data is unaudited; however, in our opinion, it includes all adjustments, consisting only of normal recurring adjustments necessary for a fair statement of the results for the interim periods. The condensed consolidated financial statements included herein have been prepared pursuant to the Securities and Exchange Commission’s (the “SEC”) rules and regulations; accordingly, certain information and footnote disclosures normally included in generally accepted accounting principles (“GAAP”) financial statements have been condensed or omitted.

The results of operations and cash flows for the three and nine months ended September 30, 2025, are not necessarily indicative of the results to be expected for future quarters or for the year ending December 31, 2025.

Our organization and business, the accounting policies we follow, and other information are contained in the notes to our consolidated financial statements filed as part of our 2024 Annual Report on Form 10-K. This quarterly report should be read in conjunction with such Annual Report on Form 10-K.

(2)	RECENT ACCOUNTING PRONOUNCEMENTS

Recent Accounting Pronouncements - Adopted

For the year ended December 31, 2024, the Company retrospectively adopted Accounting Standards Update ("ASU") 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures ("ASU 2023-07"). See “Note 14 – Segments of Business” for enhanced disclosures associated with the adoption of ASU 2023-07.

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Recent Accounting Pronouncements – Not Yet Adopted

In December 2023, the Financial Accounting Standards Board ("FASB") issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures ("ASU 2023-09"). ASU 2023-09 primarily requires enhanced disclosures to (1) disclose specific categories in the rate reconciliation, (2) disclose the amount of income taxes paid and expensed disaggregated by federal, state, and foreign taxes, with further disaggregation by individual jurisdictions if certain criteria are met, and (3) disclose income (loss) from continuing operations before income tax (benefit) disaggregated between domestic and foreign. ASU 2023-09 is effective for fiscal years beginning after December 15, 2024, with early adoption permitted. We are currently evaluating the impact of adopting ASU 2023-09, but do not expect it to have a material effect on our consolidated financial statements.

In November 2024, the FASB issued ASU 2024-04, Debt - Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversion of Convertible Debt Instruments. The objective of the standard is to improve the relevance and consistency in application of the induced conversion guidance in Subtopic 470-20, Debt with Conversion and Other Options. This standard will affect entities that settle convertible debt instruments for which the conversion privileges are changed to induce conversion. The guidance will be effective for annual reporting periods beginning after December 15, 2025, and interim reporting periods within those annual reporting periods. The Company is currently evaluating the impact of the new standard on its financial statements and related disclosures.

In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting-Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard update improves the disclosures about a public business entity’s expenses by requiring more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation and amortization) included within income statement expense captions. The guidance will be effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. The Company is currently evaluating the impact of adoption of the standard on its financial statement disclosures.

(3)	LONG-LIVED ASSET IMPAIRMENTS

During the year ended December 31, 2024, the Company recorded a $215.1 million non-cash impairment charge in our Coal Operations segment due to the results of our annual business plan review. As part of that business plan review, the Company evaluated core hole samples at several of our mines, noting the samples obtained at our Oaktown 2 mine were determined to be of a lower quality and density than that of the Oaktown 1 mine. As such, the Company decided to temporarily seal the Oaktown 2 mine, and to focus coal production at the Oaktown 1 mine, which has lower recovery costs.

The fair values of the impaired assets were determined using a discounted cash flow model, which represents Level 3 fair value measurements under the fair value hierarchy. The fair value analysis used assumptions regarding the projected economics of the Coal Operations assets, given prevailing commodity prices and operating expense levels.

For the three and nine months ended September 30, 2025, no impairment charges were recorded for long-lived assets.

(4)

INVENTORY

Inventory is valued at a lower of cost or net realizable value (“NRV”). As of September 30, 2025, and December 31, 2024, coal inventory includes NRV adjustments of $0.1 million and $0.3 million, respectively. During the quarter, as part of the Company’s routine inventory reconciliation process, a downward adjustment of $2.6 million was recorded to coal inventory.

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(5)

BANK DEBT

On June 27, 2025, the Company executed the Third Amendment (“Third Amendment”) to the Fourth Amended and Restated Credit Agreement, dated as of August 2, 2023 (as amended, the “Credit Agreement”), with PNC Bank, National Association (in its capacity as administrative agent, "PNC"), which was accounted for as a debt modification. The primary purpose of the Third Amendment was to provide additional operating flexibility for the remainder of 2025 by redefining covenants, deferring certain covenants until the third quarter of 2025 and moving our October 2025 payment to January 2026. The Third Amendment provides for additional flexibility for the Company to enter into prepaid forward power sale contracts, provided that the Company maintains one hundred percent of the outstanding aggregate principal balance of the Credit Agreement (“Term Loan”) as a compensating balance. During the second quarter of 2025, the Company entered into a $35.0 million prepaid forward power sales contract, as noted in “Note 7 – Revenue” of which $19.0 million of the proceeds were deposited into a money market account with the administrative agent. The compensating balance is classified as “restricted cash” on the condensed consolidated balance sheets at September 30, 2025. As part of the Third Amendment, the required October 2025 principal payment of $6.0 million and the January 2026 principal payment of $6.5 million, pursuant to the Term Loan, are both now due in January 2026. The balance of the Term Loan will be fully repaid no later than March 2026. All payments will be funded by withdrawals from our compensating balance held in our money market account. Furthermore, the Third Amendment defines certain administrative changes which include, among other things modifications to the required timelines related to reporting and the removal of third-party financial advisors.

On a net basis, bank debt did not change during the nine months ended September 30, 2025. Bank debt totaled $44.0 million as of September 30, 2025 and is comprised of our Term Loan ($19.0 million as of September 30, 2025) and a $75.0 million revolver ($25.0 million borrowed as of September 30, 2025) under the Credit Agreement. Our debt is recorded at amortized cost, which approximates fair value due to the variable interest rates in the agreement and is collateralized primarily by our assets.

Liquidity

As of September 30, 2025, we had additional borrowing capacity of $33.8 million under the revolver and total liquidity of $46.4 million. Our additional borrowing capacity is net of $16.2 million in outstanding letters of credit as of September 30, 2025 that were required to maintain surety bonds and other credit support obligations. Liquidity consists of our additional borrowing capacity and unrestricted cash and cash equivalents.

The Company is currently in discussions with members of its existing bank group and other lenders to refinance our current Credit Agreement. The revolving credit facility matures August 2, 2026 and our Term Loan matures March 31, 2026. The balance of the Term Loan is scheduled to be repaid in January 2026 and March 2026, utilizing restricted cash as set forth in the Third Amendment. As such, our revolving credit facility and Term Loan are listed as current on the September 30, 2025 condensed consolidated balance sheets. While no definitive agreement has been reached as of the reporting date, management believes it is probable that the Credit Agreement will be refinanced on market terms and conditions for similarly situated borrowers and consistent with the existing Credit Agreement. However, there can be no assurance that such efforts will be successful or completed on favorable terms. Failure to refinance our Credit Agreement debt prior to maturity could adversely affect the Company’s liquidity and financial condition.

Fees

Unamortized bank fees and other costs incurred in connection with our initial facility totaled $4.3 million. Additional costs incurred with our Debt Agreement amendments totaled $0.9 million, of which $0.3 million related to our Third Amendment. These unamortized bank fees were deferred and are being amortized over the term of the loan. Unamortized bank fees as of September 30, 2025, and December 31, 2024, were $1.3 million and $2.5 million, respectively. Unused borrowing capacity under the facility was $33.8 million as of September 30, 2025. Commitment fees on the unused portion of the facility are 0.50% per annum.

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Bank debt, less debt issuance costs, is presented below (in thousands):


	September 30,		December 31,
	2025		2024
Current bank debt	$	44,000	$	6,000
Less unamortized debt issuance cost		(1,302)		(1,905)
Net current portion	$	42,698	$	4,095

Long-term bank debt	$	—	$	38,000
Less unamortized debt issuance cost		—		(606)
Net long-term portion	$	—	$	37,394

Total bank debt	$	44,000	$	44,000
Less total unamortized debt issuance cost		(1,302)		(2,511)
Net bank debt	$	42,698	$	41,489


Future Maturities (in thousands):
2025	$	—
2026		44,000
Total	$	44,000

Covenants

The Third Amendment, among other things, deferred the Maximum Leverage Ratio and Minimum Debt Service Coverage Ratios until September 2025. The Maximum Leverage Ratio requirement was changed to 3.00 to 1.00 for our fiscal quarter ending September 30, 2025, and is 2.25 to 1.00 thereafter. The Debt Service Coverage Ratio requirement was changed to 3.25 to 1.00 as long as the Company maintains the required compensating balance, if not, remains at 1.25 to 1.00. The Third Amendment removed the First Lien Leverage Ratio (as defined in the First Amendment to the Credit Agreement) while maintaining the minimum liquidity requirement of $10.0 million.

As of September 30, 2025, we were in compliance with all covenants defined in the Credit Agreement.

Interest Rate

The interest rate on the facility ranges from secured overnight financing rate (“SOFR”) plus 4.00% to SOFR plus 5.00%, depending on our Leverage Ratio. As of September 30, 2025, we were paying SOFR plus 5.00% on the outstanding bank debt which equates to an all-in rate of 9.27%.

(6)	ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Accounts payable and accrued liabilities consist of the following for the indicated dates (in thousands):


	September 30,		December 31,
	2025		2024
Accounts payable	$	23,272	$	24,291
Accrued property taxes		4,337		4,185
Accrued payroll		4,655		3,258
Workers' compensation reserve		5,408		4,321
Group health insurance		1,500		1,700
Asset retirement obligation - current portion		1,397		1,952
Other		3,441		4,591
Total accounts payable and accrued liabilities	$	44,010	$	44,298

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(7)

REVENUE

Revenue from Contracts with Customers

We account for a contract with a customer when the parties have executed the contract and are committed to performing their respective obligations, the rights of each party are identified, payment terms are identified, the contract has commercial substance, and it is probable substantially all the consideration will be collected. We recognize revenue when we satisfy a performance obligation by transferring control of a good or service to a customer.

Electric operations

We concluded that for a Power Purchase Agreement (“PPA”) that is not determined to be a lease or derivative, the definition of a contract and the criteria in ASC 606, Revenue from Contracts with Customers (“ASC 606”), is met at the time a PPA is executed by the parties, as this is the point at which enforceable rights and obligations are established. Accordingly, we concluded that a PPA that is not determined to be a lease or derivative constitutes a valid contract under ASC 606.

We recognize revenue daily, based on an output method of capacity made available as part of any stand-ready obligations for contract capacity performance obligations and daily, based on an output method of MWh of electricity delivered.

For the delivered energy performance obligation in the PPA with Hoosier, we recognize revenue daily for actual delivered electricity plus the amortization of the contract liability as a result of the Asset Purchase Agreement with Hoosier. For delivered energy to all other customers, we recognize revenue daily for the actual delivered electricity.

When energy hours at the Merom Hub are priced below our production cost or during outages at Merom, we have the option to make net hourly purchases of power in the MISO market. We record these as “cost of purchased power” on our condensed consolidated statements of operations.

Coal operations

Our coal revenue is derived from sales to customers of coal produced at our facilities. Our customers typically purchase coal directly from our mine sites where the sale occurs and where title, risk of loss, and control pass to the customer at that point. Our customers arrange for and bear the costs of transporting their coal from our mines to their plants or other specified discharge points. Our customers are typically domestic utility companies. Our coal sales agreements with our customers are fixed-priced, fixed-volume supply contracts, or include a pre-determined escalation in price for each year. Price re-opener and index provisions may allow either party to commence a renegotiation of the contract price at a pre-determined time. Price re-opener provisions may automatically set a new price based on the prevailing market price or, in some instances, require us to negotiate a new price, sometimes within specified ranges of prices. The terms of our coal sales agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary by customer.

Coal sales agreements will typically contain coal quality specifications. With coal quality specifications in place, the raw coal sold by us to the customer at the delivery point must be substantially free of magnetic material and other foreign material impurities and crushed to a maximum size as set forth in the respective coal sales agreement. Price adjustments are made and billed in the month the coal sale was recognized based on quality standards that are specified in the coal sales agreement, such as Btu factor, moisture, ash, and sulfur content, and can result in either increases or decreases in the value of the coal shipped.

Disaggregation of Revenue

Revenue is disaggregated by revenue source for our Electric Operations and by primary geographic markets for our Coal Operations, as we believe this best depicts how the nature, amount, timing, and uncertainty of our revenue and cash flows are affected by economic factors.

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Electric Operations


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Delivered energy (including contract liability amortization)	$	77,776	$	56,256	$	194,044	$	148,490
Capacity		15,459		15,860		45,110		44,506
Total Electric Operations sales	$	93,235	$	72,116	$	239,154	$	192,996

Coal Operations


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Outside third-party Indiana customers	$	27,355	$	13,338	$	68,960	$	46,490
Customers in Florida, North Carolina, Alabama and Georgia		23,901		18,324		50,628		67,603
Total Coal Operations sales	$	51,256	$	31,662	$	119,588	$	114,093

Performance Obligations

Electric Operations

We concluded that each megawatt hour (“MWh”) of delivered energy is capable of being distinct as a customer could benefit from each on its own by using/consuming it as a part of its operations. We also concluded that the stand-ready obligation to be available to provide electricity is capable of being distinct as each unit of capacity provides an economic benefit to the holder and could be sold by the customer.

During the second quarter of 2025, we entered into a 17-month, $35.0 million prepaid physically delivered power contract with energy to be delivered at various periods starting in July 2025 through November 2026. During the third quarter of 2025, we entered into a 5-month, $20.0 million prepaid physically delivered power contract with energy to be delivered January 2027 through May 2027. As the total amounts paid upfront by the customers differ from the stand-alone selling price of the transferred power, the Company concluded the contracts contain a significant financing component. The contract liabilities associated with the prepayments will be accreted over the agreement term based upon the Company’s incremental borrowing rates at the time of the contract which approximates 9.50% and 9.92% for the respective contracts, and the accretion is separately recognized as interest expense.

Coal Operations

A performance obligation is a promise in a contract with a customer to provide distinct goods or services. Performance obligations are the unit of account for purposes of applying the revenue recognition standard and therefore determine when and how revenue is recognized. In most of our coal contracts, the customer contracts with us to provide coal that meets certain quality criteria. We consider each ton of coal a separate performance obligation and allocate the transaction price based on the base price per the contract, increased or decreased for quality adjustments.

The following table illustrates the balance of all current Electric and Coal Operations contracts allocated to performance obligations that are unsatisfied or partially unsatisfied as of September 30, 2025 and disaggregated by segment and contract duration.


	2025		2026		2027		2028		2029		Total
Delivered energy revenues	$	43,780	$	172,360	$	117,300	$	57,700	$	13,860	$	405,000
Capacity revenues		12,980		61,540		51,400		37,330		3,470		166,720
Coal Operations revenues (1)		27,070		151,560		141,850		29,500		—		349,980
Total revenue	$	83,830	$	385,460	$	310,550	$	124,530	$	17,330	$	921,700

(1) Coal revenues consist of consolidated revenues excluding our intercompany revenues from Merom.

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Contract Balances

Under ASC 606, the timing of when a performance obligation is satisfied can affect the presentation of accounts receivable, contract assets and contract liabilities. The main distinction between accounts receivable and contract assets is whether consideration is conditional on something other than the passage of time. A receivable is an entity’s right to consideration that is unconditional.

Under the typical payment terms of our contracts with customers, the customer pays us the contracted price for electricity or capacity. For coal contracts, the customer pays us a base price for the coal, increased or decreased for any quality adjustments. Amounts billed and due are recorded as trade accounts receivable and included in accounts receivable in our condensed consolidated balance sheets. Payments received prior to fulfilling our performance obligations are included in contract liabilities in our condensed consolidated balance sheets.

The following table shows our beginning and ending accounts receivable from contracts with customers balance for the periods presented (in thousands):


	September 30,
	2025		2024
Accounts receivable from contracts with customers - beginning balance	$	15,438	$	19,937
Accounts receivable from contracts with customers - ending balance	$	24,763	$	11,908

As the Company fulfills its contractual obligations, we recognized those amounts in revenues. The following table reconciles our beginning and ending contract liabilities for the periods presented (in thousands):


	September 30,
	2025		2024
Total contract liabilities - beginning balance	$	146,719	$	113,741
Cash payments received on future contract obligations		102,480		90,082
Accretion on contract liabilities		5,659		—
Revenue recognized, cash payment received in prior period		(82,639)		(59,236)
Revenue recognized, cash payment received in current period		(24,613)		(32,789)
Total contract liabilities - ending balance	$	147,606	$	111,798

(8)	INCOME TAXES

For the nine months ended September 30, 2025 and 2024, we recorded income taxes using an estimated annual effective tax rate based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate. The effective tax rate for the nine months ended September 30, 2025 and 2024, was ~ 0% due to recording of a full valuation allowance and ~24%, respectively. Historically, our actual effective tax rates have differed from the statutory effective rate primarily due to the benefit received from statutory percentage depletion in excess of tax basis. The deduction for statutory percentage depletion does not necessarily change proportionately to changes in income (loss) before income taxes.

On July 4, 2025, H.R.1, commonly referred to as the One Big Beautiful Bill Act (“OBBBA”) was enacted. The OBBBA includes a broad range of tax reform provisions affecting businesses, including extending and modifying certain key Tax Cuts & Jobs Act provisions (both domestic and international), expanding certain Inflation Reduction Act incentives, and accelerating the phase-out of or repealing others. We have analyzed the provisions within the act and determined that the benefits relating to capital expenditures and deductibility of interest under IRC Section 163(j) will provide cash flow benefits to the company in 2025 by accelerating deductions for tax purposes. As the material benefits relate to the timing of deductions, there were no material impact affecting the effective tax rate or the valuation allowance determination in the third quarter of 2025.

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(9)	STOCK COMPENSATION PLANS


Non-vested grants as of December 31, 2024		1,034,486
Awarded		355,258
Vested		(577,101)
Forfeited		(14,500)
Non-vested grants as of September 30, 2025		798,143

For the three and nine months ended September 30, 2025, our stock compensation expense was $0.6 million and $2.1 million, respectively. For the three and nine months ended September 30, 2024, our stock compensation expense was $1.1 million and $3.3 million, respectively.

Non-vested RSU grants will vest as follows:


Vesting Year		RSUs Vesting
2025		156,000
2026		225,714
2027		405,213
2028		11,216
		798,143

As noted in our Form 8-K filed with the SEC on June 2, 2025, on May 29, 2025, shareholders approved the Second Amended and Restated 2008 Restricted Stock Unit Plan (the “RSU Plan”) which, (i) increased the number of shares available for issuance by 2,000,000 shares, and (ii) extended the term of the RSU Plan until May 29, 2035.

As of September 30, 2025, unrecognized stock compensation expense to be recognized over the rolling 3-year vesting period is $6.4 million, and we had 1,897,154 RSUs available for future issuance. RSUs are not allocated earnings and losses as they are considered non-participating securities. Forfeitures are recognized as they occur.

(10)	SELF-INSURANCE

The Company is self-insured for certain risks, including physical damage and operational liability, related to our non-leased underground mining equipment allocated among four mining units dispersed over seven miles. The Company records a liability for self-insured risks when a loss is both probable and reasonably estimable. The Company had no accrual for self-insurance liabilities as of September 30, 2025 or December 31, 2024.

The Company also self-insures for workers’ compensation claims under a guaranteed cost program. Under this program, the Company is responsible for the first $1.0 million per claim up to an aggregate of $4.0 million annually. The Company has restricted cash of $22.8 million and $4.9 million as of September 30, 2025, and December 31, 2024, respectively, which represents cash held and controlled by third parties and is restricted primarily for future workers’ compensation claim payments and the $19.0 million compensating balance on our Term Loan (as discussed in “Note 5 – Bank Debt” above). The Company had $5.4 million and $4.3 million of workers’ compensation reserve as of September 30, 2025 and December 31, 2024, respectively, in “accounts payable and accrued liabilities” on the condensed consolidated balance sheets.

(11)	FAIR VALUE MEASUREMENTS

We account for certain assets and liabilities at fair value. The hierarchy below lists three levels of fair value based on the extent to which inputs used in measuring fair value are observable in the market. We categorize each of our fair value measurements in one of these three levels based on the lowest level input that is significant to the fair value measurement in its entirety. These levels are:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities

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occur in sufficient frequency and volume to provide pricing information on an ongoing basis. We have no Level 1 instruments.

Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. We have no Level 2 instruments.

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). ARO liabilities use Level 3 non-recurring fair value measures.

Nonrecurring Fair Value Measurements

During the fourth quarter of 2024, the Company completed its review of the coal mining facilities and future mining plans. The impairment analysis was based upon the coal mining operating plans of the Company, market driven pricing and cost trends. As part of that analysis, the Company determined the carrying amount of its coal mining long-lived asset group was not recoverable and recorded a non-cash, long-lived asset impairment charge of $215.1 million in 2024.

The discounted cash flow model was calculated using projected economics for the Coal Operations assets, using the Company’s mining plan and reserve estimates to be mined and sold at prevailing commodity prices, operating expenses, and production cost levels, which are classified as Level 3 inputs.

Credit Risk

The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, and restricted cash.

The Company’s cash and cash equivalent and restricted cash balances on deposit with financial institutions total $35.5 million and $12.2 million as of September 30, 2025 and December 31, 2024, respectively, which exceeded FDIC insured limits. The Company regularly monitors these institutions’ financial condition. The Company utilizes large and reputable banking institutions which it believes mitigates these risks. The Company has not experienced any losses in such accounts.

(12)	EQUITY METHOD INVESTMENTS

We own a 50% interest in Sunrise Energy, LLC, which owns gas reserves and gathering equipment with plans to develop and operate such reserves. Sunrise Energy, LLC, also plans to develop and explore for oil, natural gas, and coal-bed methane gas reserves on or near our underground coal reserves. The carrying value of the investment included in our condensed consolidated balance sheets as of September 30, 2025, and December 31, 2024, was $2.0 million and $2.1 million, respectively.

The Company also owns a 50% interest in Oaktown Gas, LLC. Oaktown Gas, LLC operates an emission abatement project through the destruction of gases extracted from the Oaktown mines to generate carbon credits and other emissions offset credits. The carrying value of the investment included in the condensed consolidated balance sheets as of September 30, 2025, and December 31, 2024, was $0.7 million and $0.5 million, respectively.

(13)	ORGANIZATIONAL RESTRUCTURING

On February 23, 2024, (the “Effective Date”), we committed to a reorganization effort in the Coal Operations Segment (the “Reorganization Plan”) that included a workforce reduction of approximately 110 employees, or approximately 12% of the workforce. The reduction in workforce was communicated to employees on the Effective Date and implemented immediately, subject to certain administrative procedures. The Reorganization Plan was designed to strengthen our financial and operational efficiency and create significant operational savings and higher margins in our Coal Operations segment. This step helped advance our transition from a company primarily focused on coal production to a more resilient and diversified integrated independent power producer (“IPP”). As part of this initiative, we substantially idled production at our higher cost surface mines, Prosperity Mine and Freelandville Mine, with minimal

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ongoing production. We also focused our seven units of underground equipment on four units of our lowest cost production at our Oaktown Mine. In connection with the Reorganization Plan, we incurred aggregate expenses of $1.9 million ($1.1 million in the first quarter of 2024 and $0.8 million in the second quarter of 2024) that were included in “labor” in the condensed consolidated statements of operations. These charges related to compensation, tax, professional, and insurance related expenses are considered one-time charges paid during 2024. The coal mining properties asset group was tested for impairment as result of the organizational restructuring passing the undiscounted recoverability test.

(14)	SEGMENTS OF BUSINESS

Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The CODM, who is the Company’s Chief Executive Officer, reviews and assesses operating performance measures related to our Electric Operations and our Coal Operations segments.

Our Electric Operations segment includes the electric power generation facilities of our Merom power plant, which is a two unit, 1080-megawatt rated coal fired power plant located in Sullivan County, Indiana. Our sales region is in MISO Zone 6, which includes Indiana and a portion of western Kentucky. Revenues from our Electric Operations segment consist primarily of delivered energy and capacity revenues. Fuel costs included in our Electric Operations segment include the cost of coal purchased from our Coal Operations segment, which are based on multi-year contracts which approximate market prices at the time the contracts are entered into.

Our Coal Operations segment includes the Oaktown 1 underground mining complex, as well as other currently idled mining facilities, which produce high-quality bituminous coal from the Illinois Basin. Revenues from our Coal Operations segment consist of sales of coal to various third-parties and to Merom. Coal sales to our Electric Operations are based on multi-year contracts which approximate market prices at the time the contracts are entered into. Intercompany coal sales and amounts above actual costs to produce the coal are eliminated in the consolidated statements of operations.

The CODM evaluates segment performance based upon EBITDA margin for each business segment. EBITDA margin is calculated for each segment as follows:

For our Electric Operations segment, EBITDA margin is comprised of delivered energy revenues less certain significant segment expenses, which include (i) variable costs are comprised of fuel costs and certain other operating costs, such as limestone and soda ash, (ii) other operating and maintenance costs, (iii) costs of purchased power, (iv) utilities, (v) labor and (vi) general and administrative costs.

For our Coal Operations segment, EBITDA margin is comprised of coal sales less certain significant segment expenses, which include (i) fuel, (ii) other operating and maintenance costs, (iii) utilities, (iv) labor and (v) general and administrative costs.

EBITDA margin for each segment is a key measure used by our CODM and provides information about our core operating performance, significant expenses and ability to generate cash flow. Additionally, EBITDA margin provides investors with the financial analytical framework upon which our CODM bases financial, operational, compensation and planning decisions and presents a measurement that investors, rating agencies and debt holders have indicated is useful in assessing us and our results of operations. Our CODM reviews variable costs, as defined above, in our Electric Operations segment in order to evaluate the efficiency of that segments operations.

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Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the three months ended September 30, 2025 (in thousands):


	Electric Operations			Coal Operations
Delivered Energy	$	77,776	Coal Sales	$	68,814
Capacity Revenue		15,459
Electric Sales	$	93,235

Fuel	$	(44,751)
Other Operating Costs (1)		(1)
Total Variable Costs	$	(44,752)

Other Operating and Maintenance Costs (2)	$	(9,368)	Fuel	$	(574)
Cost of Purchased Power		(2,074)	Other Operating and Maintenance Costs		(35,046)
Utilities		(1,873)	Utilities		(2,670)
Labor		(7,949)	Labor		(19,625)
Power Margin Without General and Administrative		27,219	Coal Margin Without General and Administrative		10,899
General and Administrative		(1,308)	General and Administrative		(2,062)
Electric Operations — EBITDA Margin	$	25,911	Coal Operations — EBITDA Margin	$	8,837

(1) Other operating costs primarily include costs for lime dust.

(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1).

Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the three months ended September 30, 2024 (in thousands):


	Electric Operations			Coal Operations
Delivered Energy	$	56,256	Coal Sales	$	48,320
Capacity Revenue		15,860
Electric Sales	$	72,116

Fuel	$	(30,181)
Other Operating Costs (1)		(36)
Total Variable Costs	$	(30,217)

Other Operating and Maintenance Costs (2)	$	(5,561)	Fuel	$	(572)
Cost of Purchased Power		(3,149)	Other Operating and Maintenance Costs		(27,031)
Utilities		(492)	Utilities		(3,094)
Labor		(7,360)	Labor		(19,361)
Power Margin Without General and Administrative		25,337	Coal Margin Without General and Administrative		(1,738)
General and Administrative		(1,252)	General and Administrative		(2,082)
Electric Operations — EBITDA Margin	$	24,085	Coal Operations — EBITDA Margin	$	(3,820)

(1) Other operating costs primarily include costs for lime dust.

(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1).

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Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the nine months ended September 30, 2025 (in thousands):


	Electric Operations			Coal Operations
Delivered Energy	$	194,044	Coal Sales	$	169,117
Capacity Revenue		45,110
Electric Sales	$	239,154

Fuel	$	(104,150)
Other Operating Costs (1)		(10)
Total Variable Costs	$	(104,160)

Other Operating and Maintenance Costs (2)	$	(24,602)	Fuel	$	(1,564)
Cost of Purchased Power		(11,086)	Other Operating and Maintenance Costs		(77,147)
Utilities		(3,932)	Utilities		(9,270)
Labor		(23,731)	Labor		(57,671)
Power Margin Without General and Administrative		71,643	Coal Margin Without General and Administrative		23,465
General and Administrative		(3,972)	General and Administrative		(6,290)
Electric Operations — EBITDA Margin	$	67,671	Coal Operations — EBITDA Margin	$	17,175

(1) Other operating costs primarily include costs for lime dust.

(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1).

Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the nine months ended September 30, 2024 (in thousands):


	Electric Operations			Coal Operations
Delivered Energy	$	148,490	Coal Sales	$	160,066
Capacity Revenue		44,506
Electric Sales	$	192,996

Fuel	$	(79,532)
Other Operating Costs (1)		(22)
Total Variable Costs	$	(79,554)

Other Operating and Maintenance Costs (2)	$	(22,926)	Fuel	$	(2,557)
Cost of Purchased Power		(7,694)	Other Operating and Maintenance Costs		(80,419)
Utilities		(1,451)	Utilities		(10,639)
Labor		(22,203)	Labor		(66,241)
Power Margin Without General and Administrative		59,168	Coal Margin Without General and Administrative		210
General and Administrative		(3,760)	General and Administrative		(8,012)
Electric Operations — EBITDA Margin	$	55,408	Coal Operations — EBITDA Margin	$	(7,802)

(1) Other operating costs primarily include costs for lime dust.

(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1).

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Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the three months ended September 30, 2025 (in thousands):


					Corporate and Other
Reconciliation of Revenue:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Delivered Energy	$	77,776	$	—	$	—	$	77,776
Capacity Revenue		15,459		—		—		15,459
Other Revenue		192		1,647		516		2,355
Coal Sales (Third-Party)		—		51,256		—		51,256
Coal Sales (Intercompany)		—		17,558		(17,558)		—
Operating Revenues	$	93,427	$	70,461	$	(17,042)	$	146,846

Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the three months ended September 30, 2024 (in thousands):


					Corporate and Other
Reconciliation of Revenue:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Delivered Energy	$	56,256	$	—	$	—	$	56,256
Capacity Revenue		15,860		—		—		15,860
Other Revenue		187		721		469		1,377
Coal Sales (Third-Party)		—		31,662		—		31,662
Coal Sales (Intercompany)		—		16,658		(16,658)		—
Operating Revenues	$	72,303	$	49,041	$	(16,189)	$	105,155

Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the nine months ended September 30, 2025 (in thousands):


					Corporate and Other
Reconciliation of Revenue:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Delivered Energy	$	194,044	$	—	$	—	$	194,044
Capacity Revenue		45,110		—		—		45,110
Other Revenue		3,413		4,370		997		8,780
Coal Sales (Third-Party)		—		119,588		—		119,588
Coal Sales (Intercompany)		—		49,529		(49,529)		—
Operating Revenues	$	242,567	$	173,487	$	(48,532)	$	367,522

Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the nine months ended September 30, 2024 (in thousands):


					Corporate and Other
Reconciliation of Revenue:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Delivered Energy	$	148,490	$	—	$	—	$	148,490
Capacity Revenue		44,506		—		—		44,506
Other Revenue		518		2,028		1,139		3,685
Coal Sales (Third-Party)		—		114,093		—		114,093
Coal Sales (Intercompany)		—		45,973		(45,973)		—
Operating Revenues	$	193,514	$	162,094	$	(44,834)	$	310,774

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Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes for the three months ended September 30, 2025 (in thousands):


Reconciliation of Income (Loss)					Corporate and Other
before Income Taxes:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Electric Operations — EBITDA Margin	$	25,911	$	—	$	18,206	$	44,117
Coal Operations — EBITDA Margin		—		8,837		(17,558)		(8,721)
Other Operating Revenue		192		1,647		516		2,355
Depreciation, Depletion and Amortization		(5,131)		(3,992)		(19)		(9,142)
Asset Retirement Obligations Accretion		(126)		(320)		—		(446)
Exploration Costs		—		(38)		—		(38)
Gain (loss) on disposal or abandonment of assets, net		—		2,334		—		2,334
Interest Expense		(2,585)		(2,342)		—		(4,927)
Equity Method Investment (Loss)		—		—		(248)		(248)
Corporate — General and Administrative		—		—		(1,400)		(1,400)
Income (Loss) before Income Taxes	$	18,261	$	6,126	$	(503)	$	23,884

Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes for the three months ended September 30, 2024 (in thousands):


Reconciliation of Income (Loss)					Corporate and Other
before Income Taxes:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Electric Operations — EBITDA Margin	$	24,085	$	—	$	16,998	$	41,083
Coal Operations — EBITDA Margin		—		(3,820)		(16,658)		(20,478)
Other Operating Revenue		187		721		469		1,377
Depreciation, Depletion and Amortization		(4,802)		(9,013)		(23)		(13,838)
Asset Retirement Obligations Accretion		(115)		(295)		—		(410)
Exploration Costs		—		(62)		—		(62)
Gain (loss) on disposal or abandonment of assets, net		—		290		—		290
Interest Expense		(181)		(2,511)		—		(2,692)
Loss on Extinguishment of Debt		—		—		—		—
Equity Method Investment (Loss)		—		—		(234)		(234)
Corporate — General and Administrative		—		—		(3,136)		(3,136)
Corporate — Other Operating and Maintenance Costs		—		—		(114)		(114)
Income (Loss) before Income Taxes	$	19,174	$	(14,690)	$	(2,698)	$	1,786

Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before

income taxes for the nine months ended September 30, 2025 (in thousands):


Reconciliation of Income (Loss)					Corporate and Other
before Income Taxes:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Electric Operations — EBITDA Margin	$	67,671	$	—	$	48,322	$	115,993
Coal Operations — EBITDA Margin		—		17,175		(49,529)		(32,354)
Other Operating Revenue		3,413		4,370		997		8,780
Depreciation, Depletion and Amortization		(15,456)		(14,148)		(57)		(29,661)
Asset Retirement Obligations Accretion		(369)		(941)		—		(1,310)
Exploration Costs		—		(157)		—		(157)
Gain (loss) on disposal or abandonment of assets, net		—		2,410		—		2,410
Interest Expense		(6,208)		(6,261)		—		(12,469)
Equity Method Investment (Loss)		—		—		(287)		(287)
Corporate — General and Administrative		—		—		(8,834)		(8,834)
Income (Loss) before Income Taxes	$	49,051	$	2,448	$	(9,388)	$	42,111

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Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes for the nine months ended September 30, 2024 (in thousands):


Reconciliation of Income (Loss)					Corporate and Other
before Income Taxes:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Electric Operations — EBITDA Margin	$	55,408	$	—	$	47,405	$	102,813
Coal Operations — EBITDA Margin		—		(7,802)		(45,973)		(53,775)
Other Operating Revenue		518		2,028		1,139		3,685
Depreciation, Depletion and Amortization		(14,197)		(28,671)		(62)		(42,930)
Asset Retirement Obligations Accretion		(339)		(869)		—		(1,208)
Exploration Costs		—		(179)		—		(179)
Gain (loss) on disposal or abandonment of assets, net		—		536		—		536
Interest Expense		(515)		(8,908)		(941)		(10,364)
Loss on Extinguishment of Debt		—		—		(2,790)		(2,790)
Equity Method Investment (Loss)		—		—		(740)		(740)
Corporate — General and Administrative		—		—		(8,446)		(8,446)
Corporate — Other Operating and Maintenance Costs		—		—		(337)		(337)
Income (Loss) before Income Taxes	$	40,875	$	(43,865)	$	(10,745)	$	(13,735)

Presented below are our Electric and Coal Operations assets and capital expenditures for the periods presented below (in thousands):


					Corporate and Other
Other Reconciliations:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Assets at September 30, 2025	$	233,865	$	153,514	$	22,082	$	409,461
Assets at December 31, 2024	$	220,477	$	144,519	$	4,124	$	369,120
Capital Expenditures at September 30, 2025	$	25,369	$	18,908	$	—	$	44,277

Presented below are our Electric and Coal Operations assets and capital expenditures for the periods presented below (in thousands):


					Corporate and Other
Other Reconciliations:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Assets at September 30, 2024	$	217,826	$	357,913	$	3,991	$	579,730
Assets at December 31, 2023	$	208,331	$	376,387	$	5,062	$	589,780
Capital Expenditures at September 30, 2024	$	16,121	$	23,002	$	483	$	39,606

(15)	NET INCOME (LOSS) PER SHARE

The following table (in thousands, except per share amounts) sets forth the computation of basic earnings (loss) per share for the periods indicated:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Basic earnings per common share:
Net income (loss) - basic	$	23,884	$	1,554	$	42,111	$	(10,346)
Weighted average shares outstanding - basic		43,007		42,598		42,869		38,455
Basic earnings (loss) per common share	$	0.56	$	0.04	$	0.98	$	(0.27)

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The following table (in thousands, except per share amounts) sets forth the computation of diluted net income (loss) per share:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Diluted earnings per common share:
Net income (loss) - diluted	$	23,884	$	1,554	$	42,111	$	(10,346)

Weighted average shares outstanding - basic		43,007		42,598		42,869		38,455
Add: Dilutive effects of Restricted Stock Units		427		420		418		—
Weighted average shares outstanding - diluted		43,434		43,018		43,287		38,455

Diluted net income (loss) per share	$	0.55	$	0.04	$	0.97	$	(0.27)

(16)	CONTINGENCIES

Our Coal Operations subsidiary is party to litigation in which the plaintiffs allege violations of the Fair Labor Standards Act and state law due to alleged failure to compensate for time "donning" and "doffing" equipment and to account for certain bonuses in the calculation of overtime rates and pay. In January 2025, we agreed to settle with the plaintiffs such litigation for $2.8 million, which was recorded in “operating expenses” on our consolidated statements of operations for the year ended December 31, 2024. During the third quarter of 2025, $2.7 million was transferred into an escrow account while the settlement is pending court approval of the settlement terms. At September 30, 2025, $0.1 million related to the settlements remains in “accounts payable and accrued liabilities” on our condensed consolidated balance sheets at September 30, 2025.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THE FOLLOWING DISCUSSION UPDATES THE MD&A SECTION OF OUR 2024 ANNUAL REPORT ON FORM 10-K AND SHOULD BE READ IN CONJUNCTION THEREWITH.

We are pleased with our favorable results in the third quarter, during which time we generated $146.8 million of revenue with $23.9 million of net income, representing substantial improvement over the $105.2 million of revenue with $1.6 million of net income generated in the prior year period. For the nine months ended September 30, 2025, we generated $367.5 million of revenue with $42.1 million of net income both materially above prior year performance.

Traditional summer weather patterns coupled with higher energy demand and higher natural gas prices provided for a supportive energy-pricing environment during the quarter that led to higher revenue at our Hallador Power subsidiary. Following the completion of Unit 2’s annual maintenance outage in early July 2025, both units operated very well throughout the quarter. We also saw positive results in our Coal Operations resulting from solid coal production, increased shipments and consistent operating costs. The favorable power markets led to increased dispatch levels at both Merom and customer plants, which provided a boost to coal shipments and helped to decrease coal inventories at both the power plant and the mine.

During the third quarter 2025 , the Company entered into a $20.0 million prepaid forward power sales contract with scheduled deliveries throughout the first half of 2027. As we have previously noted, these firm forward sales allow us to improve liquidity from lower future price environments and also provides an advantage, as we saw in this instance, when pricing is stronger. These prepaid sales help us to lock in prices in the near term as we continue to focus on securing a long-term power purchase agreement in support of utility, data center and/or other large scale industrial development. The prepaid funds will be used to support company operations and capital expenditures.

We continue to see significant and accelerating interest in our capacity and energy offerings. As the third quarter progressed, we saw increased activity from both data center developers and load serving entities seeking the scarce inventory of large blocks of capacity and energy that we have available in the coming decade. We are in advanced discussions on both fronts and anticipate making positive progress towards a long-term agreement with a data center developer or load serving entity by early 2026. Each of the interested parties brings a unique perspective to the negotiations and each presents differentiated value creation opportunities and challenges to effectively monetize our capacity and energy offerings. We continue to believe that the evolving energy markets, specifically related to data center growth and favorable load serving entity demand, as well as the newly supportive regulatory environment, are providing us with opportunities that were not available when we began the request for proposal process. We also recognize that these opportunities have an undefined lifespan and we continue to work diligently to secure an agreement that will benefit the Company and our shareholders, both now and in the future.

While we still believe that an agreement with a load serving entity is intrinsically more straightforward to negotiate, can be implemented sooner and could result in greater sales volumes of energy and accredited capacity, we are beginning to see improving timelines on the developer side, especially where the developers had the foresight to speculatively acquire required infrastructure, such as step-down transformers, switch gear and other site-specific level electrical equipment. We anticipate favorable pricing in these potential opportunities, but, as we have highlighted before, data center arrangements are inherently more complex and involve multiple parties, which by its nature adds time and alignment challenges to the negotiation process. Notwithstanding those challenges, returning to non-exclusive negotiations reinforced our belief that we will forge a strategic partnership and create significant value for years to come.

Throughout the past several years, we have expressed our strong belief that the prevailing industry trend of retiring dispatchable generators in favor of non-dispatchable resources, such as wind and solar, will create and has created an unbalanced supply and demand equation, resulting in reduced availability and increased price of accredited capacity. It is our position that the enhanced reliability of dispatchable generation, like Merom, versus non-dispatchable generators will increase the value of the attributes of Hallador Power in the overall energy markets. With this in mind, we continue to evaluate the potential to enhance value through strategic growth initiatives such as the acquisition of retiring or retired generation assets and infrastructure. We are regularly evaluating potential acquisition opportunities to diversify and

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increase our dispatchable generation as well as other strategic opportunities, which we believe would inherently diversify our generation portfolio, and provide an avenue to realize future growth opportunities. We believe that this approach has the potential to enhance our financial flexibility and strengthen our position in the evolving energy market.

We remain optimistic about the potential to add to our strategic generation portfolio and the long-term benefits that such a transaction could produce for the company, its shareholders and its customers. This model for growth enables us to capture value by providing accredited capacity and reliable energy. In connection with this belief, on November 3, 2025, Hallador Power submitted an application to MISO’s Expedited Resource Addition Study (ERAS) program to add an additional 525 MW of gas generation at the Merom site. Given the strong market signals that we are currently seeing for our product offerings and the robust interest in the types of long-term arrangements that we are currently evaluating, we believe that it is an appropriate time to explore increasing generation at Merom. While the application is only a first step in our growth process and does not guarantee that we will be able to add the full load which we applied for, or any additional generation as part of ERAS, we are excited to participate in the opportunity and for what it could mean to the future of Hallador. We are currently targeting the generation to come online late in 2028. The process is capital intensive and includes operational, financial, regulatory and legal risks that could impact the project’s viability and/or timeline.

Additionally, we see the potential of enhancing Merom’s reliability, resiliency and flexibility by incorporating natural gas and creating a dual fuel configuration should operational and financial conditions support it. While we remain in the evaluation process, by adding the capability to co-fire with gas or coal, we believe that it could provide Hallador Power and its customers the ability to take advantage of economic fluctuations in fuel cost and provide potential flexibility as we manage other operating expenses. We believe that the ability to co-fire with natural gas and coal will also provide increased resiliency in times where gas availability is limited and allow us to retain the economic advantages of operating our Sunrise Coal subsidiary and leveraging our own fuel supply to ensure competitively priced offerings from third party fuel providers. This evaluation is complex on a variety of levels, specifically customer preference and an evolving regulatory environment, each of which could materially impact the timing and economic benefits of undertaking such a change.

In 2024, we delivered 2.9 million MWh of energy during the first nine months at an average sales price of $50.97 per MWh. In 2025, we delivered 4.0 million MWh of energy during the first nine months at an average sales price of $48.88. As illustrated in the forward sales position table, below, following 2026, we are optimistic that we will be able to sell energy at higher prices in support of data center development and/or to traditional wholesale customers in line with the indicators of a strong forward energy pricing curve.

Shifting to our Coal Operations, during the quarter, we saw improvements in operational expenses and increased shipments. The improved dispatch levels at Merom and our customers’ plants helped to reduce our previously elevated inventories, while still allowing us adequate fuel inventory to position us well to meet industry needs if power plants, including Merom, dispatch at higher levels over the course of the upcoming Winter season.

With renewed support of coal mining and coal fired generation on both the federal and state level, we believe that we are well-positioned to take advantage of opportunities for strategic growth and/or organic expansion. We believe that current market dynamics remain stronger than they were in the past year, and we are actively assessing the timing and feasibility of expanding coal production in 2026. As we have previously said, our average contracted sales price in 2026 across all coal sales contracts is approximately $4.00 per ton higher than the average contracted sales price in 2025.

We currently expect to produce approximately 3.8 million tons of coal in 2025. In the first three quarters of 2025, we produced 3.1 million tons of coal at our Oaktown Mining Complex. We also use supplemental coal from third party suppliers at Merom, typically purchased at favorable prices to help diversify self-production supply risk and to provide us with additional flexibility in our ability to rapidly respond to customer demand if spot market pricing justifies doing so. This optionality to obtain low-cost fuel either internally or from third-parties while capturing upward swings in the commodity markets for coal should allow us to further maximize margins while optimizing fuel costs at Merom.

The continued transformation of Hallador from a commodity focused producer of coal to a vertically integrated IPP remains our primary focus. This allows us to leverage the ongoing impacts of the energy transition to capture the

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expanding margins of the energy markets and capitalize on the rising demand for reliable electricity. As described above, we continue to see very strong interest from data center developers and load serving entities with respect to our energy and accredited capacity offerings. This interest and the number of inquiries accelerated throughout the quarter and we are encouraged by the variety of interested parties and the varied deal structures that we are seeing with respect to our offerings. We continue to believe that our business is well positioned to take advantage of opportunities for growth and cash flow generation as they arise.

Like our competitors, Hallador’s business is affected by various macroeconomic factors, including tariffs and inflationary trends. The U.S. has implemented, or is considering implementing, higher tariffs on imports into the U.S. While such tariffs could potentially result in reduced economic activity, increased costs in operating our business including potential supply chain disruptions, and changes in purchasing behaviors for thermal coal or other potentially adverse economic outcomes, tariffs (or retaliatory trade measures imposed by other countries on U.S. goods) have not yet had a significant impact on our business or results of operations.

Our goal is for Hallador Power to generate up to 6.0 million MWh annually (see Hallador Power’s capacity and utilization information below), if the markets and energy pricing support that level of generation. During the first nine months of the year, Hallador Power generated approximately 3.7 million MWh, or roughly 82.0% of our year-to-date target and economically purchased 0.3 million MWh.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Power Capacity and Utilization
Nameplate capacity (MW)⁽ⁱ⁾	1,080		1,080		1,080		1,080
Accredited capacity for the period (MW)⁽ⁱⁱ⁾	748		828		821		858
Accredited capacity utilization⁽ⁱⁱⁱ⁾	93	%	59	%	69	%	47	%

(i).

Nameplate capacity for the Merom Power Plant refers to the maximum electric output generated by the plant in the period presented and may not reflect actual production. Actual production each period varies based on weather conditions, operational conditions, and other factors.

(ii).

Accredited capacity is based on MISO’s average seasonal accreditations for the year. Average seasonal accreditations were 775 MW and 829 MW per day for 2025 and 2024, respectively. Accreditations are weighted and adjusted annually based on 3-year rolling performance metrics.

(iii).

Accredited capacity utilization is measured as power produced (MWh) divided by accredited capacity for the period (MW) multiplied by 24, times the number of days for the period.

When forward selling Capacity, we target annual sales of around $65.0 million to offset our fixed annual costs at the plant of approximately $60.0 million. For 2025, we have contracted approximately $58.1 million or 89.4% of our target. We believe our forward Capacity sales goals are attainable as illustrated in our “Forward Sales Position” table below.

Our condensed consolidated financial statements should be read in conjunction with this discussion. This analysis includes a discussion of metrics on a per mega-watt hour (MWh) and a per ton basis as derived from the condensed consolidated financial statements, which are considered non-GAAP measurements. These metrics are significant factors in assessing our operating results and profitability.

OVERVIEW

The following is an overview our Electric Operations and Coal Operations results for Q3 2025 compared to Q2 2025.

Q3 2025 Net Income of $23.9 million.

Electric Operations:

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In Q3 2025, Total Electric Sales were $93.2 million, or $59.09 per MWh sold, an increase of $33.2 million or 55.3% from Q2 2025.

ii.

In Q3 2025, Total Electric Operations expenses on a segment basis were $75.2 million or $47.64 per MWh sold an increase of $23.7 million or 46.0% from Q2 2025.

iii.

Q3 2025 Electric Operations net income was $18.3 million an increase of $6.7 million or 57.8% from Q2 2025.

Key drivers in Q3 2025 Electric Operations results were:

(1)During the third quarter of 2025, we sold 1.6 million MWh representing a 100.0% increase in total MWh sold from the second quarter of 2025. This increase was expected as Q2 2025 typically has lower demand for power and we had a planned maintenance outage on one of our units at Merom for approximately two months during the second quarter. On a per MWh basis, Q3 Electrics Sales were $59.09 per MWh sold compared to $72.44 per MWh sold in Q2 2025. The variance on a per MWh basis was primarily due to the allocation of capacity revenue over increased energy volumes.

(2)In Q3 2025, significant operating costs including fuel, other operating and maintenance and cost of purchased power were $56.2 million, or $35.61 per MWh compared to $34.2 million, or $41.31 per MWh in Q2 2025. The increase in costs reflect the higher plant output and planned maintenance as also reflected in the decreased cost per MWh from Q2.

(3)

Q3 2025 Electric Operations income before income taxes was $18.3 million or $11.57 per MWh, an increase of $6.7 million and a decrease of $2.42 per MWh from Q2 2025.

Coal Operations:

In Q3 2025, Total Coal Sales on a segment basis were $68.8 million, or $50.79 per ton sold, an increase of $23.3 million or 51.2% from Q2 2025.

ii.

In Q3 2025, Total Coal Operations Expenses on a segment basis were $66.7 million, or $49.20 per ton sold, an increase of $21.1 million or 46.3% from Q2 2025.

iii.

Q3 2025 Coal Operations Net Income on a segment basis was $6.1 million an increase of 335.7% from Q2 2025.

Key drivers in Q3 2025 Coal Operations results were:

(1)

In Q3 2025, tons sold were 1.4 million tons on a segment basis at an average price per ton of $50.79, with approximately 0.3 million tons of that being shipped to Merom for $17.6 million compared to 0.9 million tons sold in Q2 2025 at an average price of $51.16, with approximately 0.1 million tons of that being shipped to Merom for $7.4 million. This increase was expected as Q2 is the shoulder season and typically has lower demand for coal at both Merom and third-party customers.

(2)

In Q3 2025, Other operating and maintenance costs were $35.0 million, or $25.86 per ton, compared to $18.2 million, or $20.50 per ton, on a segment basis, in Q2 2025. This increase is mainly attributable to an increase of sales related royalties of $3.0 million and an increase of $14.9 million in coal cost of sales directly related to the increase in sales.

(3)

Q3 2025 Coal Operations income before income taxes was $6.1 million or $4.53 per ton on a segment basis. This is an increase of $4.7 million or $2.95 per ton from Q2 2025.

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II.

Forward Sales Position (unaudited)*


	Q4 2025		2026		2027		2028		2029		Total
Power
Energy
Contracted MWh (in millions)		1.15		4.00		2.31		1.09		0.27		8.82
Average contracted price per MWh	$	38.07	$	43.09	$	50.78	$	52.94	$	51.33
Contracted revenue (in millions)	$	43.78	$	172.36	$	117.30	$	57.70	$	13.86	$	405.00

HALLADOR ENERGY CO 10-Q