HALLADOR ENERGY CO_March 31, 2025

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 March 31, 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 May 8, 2025, we had 42,976,180 shares of common stock outstanding.

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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	4

Condensed Consolidated Statements of Stockholders’ Equity	6

Notes to Condensed Consolidated Financial Statements	7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	20

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	30

ITEM 4. CONTROLS AND PROCEDURES	31

PART II - OTHER INFORMATION	33

ITEM 4. MINE SAFETY DISCLOSURES	33

ITEM 6. EXHIBITS	33

SIGNATURES	34

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Hallador Energy Company

Condensed Consolidated Balance Sheets

(in thousands, except per share data)

(unaudited)


	March 31,		December 31,
	2025		2024
ASSETS
Current assets:
Cash and cash equivalents	$	6,891	$	7,232
Restricted cash		9,316		4,921
Accounts receivable		12,582		15,438
Inventory		36,318		36,685
Parts and supplies		40,137		39,104
Prepaid expenses		1,808		1,478
Total current assets		107,052		104,858
Property, plant and equipment:
Land and mineral rights		70,307		70,307
Buildings and equipment		435,329		429,857
Mine development		94,725		92,458
Finance lease right-of-use assets		13,034		13,034
Total property, plant and equipment		613,395		605,656
Less - accumulated depreciation, depletion and amortization		(360,624)		(347,952)
Total property, plant and equipment, net		252,771		257,704
Equity method investments		2,370		2,607
Other assets		3,904		3,951
Total assets	$	366,097	$	369,120

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of bank debt, net	$	16,965	$	4,095
Accounts payable and accrued liabilities		45,652		44,298
Current portion of lease financing		7,067		6,912
Contract liabilities - current		107,368		97,598
Total current liabilities		177,052		152,903
Long-term liabilities:
Bank debt, net		4,000		37,394
Long-term lease financing		6,921		8,749
Asset retirement obligations		15,386		14,957
Contract liabilities - long-term		42,539		49,121
Other		4,851		1,711
Total long-term liabilities		73,697		111,932
Total liabilities		250,749		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 March 31, 2025 and December 31, 2024, respectively		430		426
Additional paid-in capital		190,378		189,298
Retained earnings (deficit)		(75,460)		(85,439)
Total stockholders’ equity		115,348		104,285
Total liabilities and stockholders’ equity	$	366,097	$	369,120

See accompanying notes to the condensed consolidated financial statements.

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Hallador Energy Company

Condensed Consolidated Statements of Operations

(in thousands, except per share data)

(unaudited)


	Three Months Ended March 31,
	2025		2024
SALES AND OPERATING REVENUES:
Electric sales	$	85,943	$	60,681
Coal sales		30,185		49,630
Other revenues		1,659		1,263
Total sales and operating revenues		117,787		111,574
EXPENSES:
Fuel		15,210		8,059
Other operating and maintenance costs		28,389		37,262
Cost of purchased power		6,840		1,926
Utilities		4,152		4,594
Labor		27,029		35,168
Depreciation, depletion and amortization		14,977		15,443
Asset retirement obligations accretion		427		399
Exploration costs		21		70
General and administrative		6,825		5,944
Gain on disposal or abandonment of assets, net		(21)		(24)
Total operating expenses		103,849		108,841

INCOME FROM OPERATIONS		13,938		2,733

Interest expense (1)		(3,723)		(3,937)
Loss on extinguishment of debt		—		(853)
Equity method investment (loss)		(236)		(249)
NET INCOME (LOSS) BEFORE INCOME TAXES		9,979		(2,306)

INCOME TAX EXPENSE (BENEFIT):
Current		—		—
Deferred		—		(610)
Total income tax expense (benefit)		—		(610)

NET INCOME (LOSS)	$	9,979	$	(1,696)

NET INCOME (LOSS) PER SHARE:
Basic	$	0.23	$	(0.05)
Diluted	$	0.23	$	(0.05)

WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		42,619		34,816
Diluted		43,462		34,816

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(1) Interest Expense:
Interest on bank debt	$	1,494	$	2,805
Other interest		1,732		728
Amortization:
Amortization of debt issuance costs		497		404
Total amortization		497		404
Total interest expense	$	3,723	$	3,937

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)


	Three Months Ended March 31,
	2025		2024
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	9,979	$	(1,696)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax (benefit)		—		(610)
Equity method investment loss		236		249
Depreciation, depletion and amortization		14,977		15,443
Loss on extinguishment of debt		—		853
Gain on disposal or abandonment of assets, net		(21)		(24)
Amortization of debt issuance costs		497		404
Asset retirement obligations accretion		427		399
Cash paid on asset retirement obligation reclamation		(156)		(639)
Stock-based compensation		1,084		666
Amortization of contract liabilities		(35,669)		(24,529)
Accretion on contract liabilities		1,560		—
Change in current assets and liabilities:
Accounts receivable		2,856		5,709
Inventory		367		(6,613)
Parts and supplies		(1,033)		(1,483)
Prepaid expenses		(330)		(37)
Accounts payable and accrued liabilities		3,124		(8,015)
Contract liabilities		37,297		35,355
Other		3,224		937
Net cash provided by operating activities	$	38,419	$	16,369

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Hallador Energy Company

Condensed Consolidated Statements of Cash Flows

(in thousands)

(unaudited)

(continued)


	Three Months Ended March 31,
	2025		2024
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	$	(11,693)	$	(14,874)
Proceeds from sale of equipment		21		24
Net cash used in investing activities		(11,672)		(14,850)

CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on bank debt		(33,000)		(26,500)
Borrowings of bank debt		12,000		12,000
Payments on lease financing		(1,693)		(1,238)
Proceeds from sale and leaseback arrangement		—		1,927
Issuance of related party notes payable		—		5,000
Debt issuance costs		—		(38)
ATM offering		—		6,580
Taxes paid on vesting of RSUs		—		(1)
Net cash used in financing activities		(22,693)		(2,270)
Increase (decrease) in cash, cash equivalents, and restricted cash		4,054		(751)
Cash, cash equivalents, and restricted cash, beginning of period		12,153		7,123
Cash, cash equivalents, and restricted cash, end of period	$	16,207	$	6,372

CASH, CASH EQUIVALENTS, AND RESTRICTED CASH:
Cash and cash equivalents	$	6,891	$	1,635
Restricted cash		9,316		4,737
	$	16,207	$	6,372

SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	1,830	$	3,083

SUPPLEMENTAL NON-CASH FLOW INFORMATION:
Change in capital expenditures included in accounts payable and prepaid expense	$	(1,649)	$	(5,290)
Stock issued on redemption of convertible notes and interest	$	—	$	9,721

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		Earnings		Equity
Balance, December 31, 2024	42,621	$	426	$	189,298	$	(85,439)	$	104,285
Stock-based compensation	—		—		1,084		—		1,084
Stock issued on vesting of RSUs	513		5		(5)		—		—
Taxes paid on vesting of RSUs	(156)		(1)		1		—		—
Net Income	—		—		—		9,979		9,979
Balance, March 31, 2025	42,978	$	430	$	190,378	$	(75,460)	$	115,348


				Additional				Total
	Common Stock Issued			Paid-in		Retained		Stockholders’
	Shares	Amount		Capital		Earnings		Equity
Balance, December 31, 2023	34,052	$	341	$	127,548	$	140,699	$	268,588
Stock-based compensation	—		—		666		—		666
Stock issued on vesting of RSUs	321		3		(3)		—		—
Taxes paid on vesting of RSUs	(132)		(1)		—		—		(1)
Stock issued on redemption of convertible notes	1,582		15		9,706		—		9,721
Stock issued in ATM offering	711		7		6,573		—		6,580
Net loss	—		—		—		(1,696)		(1,696)
Balance, March 31, 2024	36,534	$	365	$	144,490	$	139,003	$	283,858

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 months ended March 31, 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 months ended March 31, 2025 and 2024, 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 March 31, 2025, and December 31, 2024, coal inventory includes NRV adjustments of $0.1 million and $0.3 million, respectively.

(5)

BANK DEBT

On September 27, 2024, the Company executed the First Amendment (“First 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 First Amendment was to provide the Company with short-term covenant relief to pursue

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additional liquidity. The First Amendment provides for additional flexibility for the Company to enter into prepaid forward power sale contracts, provided that the Company repays outstanding term loans under the Credit Agreement (“Term Loan”) with proceeds received from certain eligible power purchase agreements, up to a maximum of $20.0 million. These required prepaid forward power sale Term Loan repayments, if any, will take the place of the $6.5 million quarterly Term Loan payments. During the fourth quarter of 2024, the Company entered into a prepaid forward power sales contract in which $20.0 million of the proceeds were used to pay our required $6.5 million quarterly loan payments through the third quarter of 2025 and also reduced our fourth quarter 2025 payment to $6.0 million. Furthermore, the First Amendment defines certain administrative changes which include, among other things, added requirements related to reporting, third party financial advisors, and appraisals on coal and power assets.

Bank debt reduced by $21.0 million during the three months ended March 31, 2025. Bank debt totaled $23.0 million and is comprised of our Term Loan ($19.0 million as of March 31, 2025) and a $75.0 million revolver ($4.0 million borrowed as of March 31, 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 March 31, 2025, we had additional borrowing capacity of $52.8 million under the revolver and total liquidity of $69.0 million. Our additional borrowing capacity is net of $18.2 million in outstanding letters of credit as of March 31, 2025 that were required to maintain surety bonds. Liquidity consists of our additional borrowing capacity and cash and cash equivalents.

Fees

Unamortized bank fees and other costs incurred in connection with our initial facility totaled $4.3 million. Additional costs incurred with the First Amendment totaled $0.6 million. These unamortized bank fees were deferred and are being amortized over the term of the loan. Unamortized bank fees as of March 31, 2025, and December 31, 2024, were $2.0 million and $2.5 million, respectively.

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


	March 31,		December 31,
	2025		2024
Current bank debt	$	19,000	$	6,000
Less unamortized debt issuance cost		(2,035)		(1,905)
Net current portion	$	16,965	$	4,095

Long-term bank debt	$	4,000	$	38,000
Less unamortized debt issuance cost		—		(606)
Net long-term portion	$	4,000	$	37,394

Total bank debt	$	23,000	$	44,000
Less total unamortized debt issuance cost		(2,035)		(2,511)
Net bank debt	$	20,965	$	41,489


Future Maturities (in thousands):
2025	$	6,000
2026		17,000
Total	$	23,000

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Covenants

The First Amendment, among other things, provided the Company with short-term covenant relief to pursue additional liquidity. The First Amendment waived the Company’s Leverage Ratio requirement for the third and fourth quarters of 2024, increased the threshold to 5.50 to 1.00 for the first quarter of 2025, and decreased the threshold back to 2.25 to 1.00 for each fiscal quarter thereafter. Additionally, the Debt Service Coverage Ratio requirement (1.25 to 1.00) was waived from third quarter of 2024 through the first quarter of 2025. The First Amendment also added additional financial covenants which include: (i) a maximum First Lien Leverage Ratio for the first quarter of 2025, calculated as of the end of each fiscal quarter for the trailing twelve months, not to exceed 3.50 to 1.00; (ii) a minimum liquidity requirement of $10.0 million, beginning on the First Amendment execution date and ending when the second quarter of 2025 compliance certificate is received; and (iii) a minimum quarterly EBITDA requirement, as defined in the First Amendment, of $5.0 million for the third quarter of 2024 through the first quarter of 2025.

As of March 31, 2025, our Leverage Ratio and First Lien Leverage Ratios were 1.89, liquidity of $69.0 million and quarterly adjusted EBITDA of $19.3 million were in compliance with the requirements of the Credit Agreement.

As of March 31, 2025, we were in compliance with all other 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 March 31, 2025, we were paying SOFR plus 5.00% on the outstanding bank debt which equates to an all-in rate of 9.45%.

(6)	ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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


	March 31,		December 31,
	2025		2024
Accounts payable	$	26,002	$	24,291
Accrued property taxes		4,671		4,185
Accrued payroll		4,374		3,258
Workers' compensation reserve		4,805		4,321
Group health insurance		1,650		1,700
Asset retirement obligation - current portion		1,697		1,952
Other		2,453		4,591
Total accounts payable and accrued liabilities	$	45,652	$	44,298

(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.

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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 our Merom Facility, 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.

Electric operations


	Three Months Ended March 31,
	2025		2024
Delivered energy (including contract liability amortization)	$	72,136	$	48,908
Capacity		13,807		11,773
Total Electric Operations sales	$	85,943	$	60,681

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Coal operations


	Three Months Ended March 31,
	2025		2024
Outside third-party Indiana customers	$	20,314	$	18,103
Customers in Florida, North Carolina, Alabama and Georgia		9,871		31,527
Total Coal Operations sales	$	30,185	$	49,630

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.

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 March 31, 2025 and disaggregated by segment and contract duration.


	2025		2026		2027		2028		2029		Total
Delivered energy revenues	$	113,090	$	149,280	$	97,290	$	57,700	$	13,860	$	431,220
Capacity revenues		45,450		61,540		51,400		37,330		3,470		199,190
Coal Operations revenues		112,600		138,730		141,850		29,500		—		422,680
Total revenue (1)	$	271,140	$	349,550	$	290,540	$	124,530	$	17,330	$	1,053,090

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

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.

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


	March 31,
	2025		2024
Accounts receivable from contracts with customers - beginning balance	$	15,438	$	19,937
Accounts receivable from contracts with customers - ending balance	$	12,582	$	14,228

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):


	March 31,
	2025		2024
Total contract liabilities - beginning balance	$	146,719	$	113,741
Cash payments received on future contract obligations		37,296		35,355
Accretion on contract liabilities		1,560		—
Revenue recognized, cash payment received in prior period		(35,668)		(24,529)
Total contract liabilities - ending balance	$	149,907	$	124,567

(8)	INCOME TAXES

For the three months ended March 31, 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 three months ended March 31, 2025 and 2024, was 0% due to recording of a full valuation allowance and ~26%, 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.

(9)	STOCK COMPENSATION PLANS


Non-vested grants as of December 31, 2024		1,034,486
Vested - weighted average share price on vested date was $12.28		(513,068)
Forfeited		(7,000)
Non-vested grants as of March 31, 2025		514,418

For the three months ended March 31, 2025 and 2024, our stock compensation expense was $1.1 million and $0.7 million, respectively.

Non-vested RSU grants will vest as follows:


Vesting Year		RSUs Vesting
2025		162,000
2026		176,210
2027		176,208
		514,418

The outstanding RSUs have a value of $6.3 million based on the March 31, 2025 closing stock price of $12.28.

As of March 31, 2025, unrecognized stock compensation expense to be recognized over the rolling 3-year vesting period is $1.5 million, and we had 217,319 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.

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(10)	SELF-INSURANCE

We self-insure our non-leased underground mining equipment. Such equipment was allocated among four mining units dispersed over seven miles, at March 31, 2025 and December 31, 2024. The historical cost of such equipment was approximately $160.8 million and $227.8 million as of March 31, 2025, and December 31, 2024.

We also self-insure for workers’ compensation claims under a guaranteed cost program. Under this program, we are responsible for the first $1.0 million per claim up to an aggregate of $4.0 million annually. Restricted cash of $3.3 million and $3.4 million as of March 31, 2025, and December 31, 2024, respectively, represents cash held and controlled by a third party and is restricted primarily for future workers’ compensation claim payments. The Company had $4.8 million and $4.3 million of workers’ compensation reserve as of March 31, 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 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 $16.2 million and $12.2 million as of March 31, 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.

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(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 March 31, 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 March 31, 2025, and December 31, 2024, was $0.4 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 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 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.

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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, (ii) other operating and maintenance costs, (iii) costs of purchased power, (iv) utilities, (v) labor and (vi) general and administrative costs. Variable operating costs are comprised of fuel costs and certain other operating costs, such as limestone and soda ash.

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.

Presented below are the Electric and Coal Operations key metrics reviewed by the CODM at March 31, 2025 (in thousands):


	Electric Operations			Coal Operations

Delivered Energy	$	72,136	Coal Sales	$	54,774
Capacity Revenue		13,807
Electric Sales	$	85,943

Fuel	$	(38,071)
Other Operating Costs (1)		(8)
Total Variable Costs	$	(38,079)

Other Operating and Maintenance Costs (2)	$	(4,527)	Fuel	$	(556)
Cost of Purchased Power		(6,840)	Other Operating and Maintenance Costs		(23,854)
Utilities		(676)	Utilities		(3,476)
Labor		(8,143)	Labor		(18,886)
Power Margin Without General and Administrative		27,678	Coal Margin Without General and Administrative		8,002
General and Administrative		(1,535)	General and Administrative		(2,313)
Electric Operations — EBITDA Margin	$	26,143	Coal Operations — EBITDA Margin	$	5,689

(1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.
(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 at March 31, 2024 (in thousands):


	Electric Operations			Coal Operations

Delivered Energy	$	48,908	Coal Sales	$	66,036
Capacity Revenue		11,773
Electric Sales	$	60,681

Fuel	$	(24,435)
Other Operating Costs (1)		(493)
Total Variable Costs	$	(24,928)

Other Operating and Maintenance Costs (2)	$	(4,886)	Fuel	$	(1,235)
Cost of Purchased Power		(1,926)	Other Operating and Maintenance Costs		(31,791)
Utilities		(302)	Utilities		(4,292)
Labor		(7,683)	Labor		(27,485)
Power Margin Without General and Administrative		20,956	Coal Margin Without General and Administrative		1,233
General and Administrative		(1,058)	General and Administrative		(2,438)
Electric Operations — EBITDA Margin	$	19,898	Coal Operations — EBITDA Margin	$	(1,205)

(1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.
(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 revenues reconciled to our consolidated operating revenues at March 31, 2025 (in thousands):


					Corporate and Other
Reconciliation of Revenue:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Delivered Energy	$	72,136	$	—	$	—	$	72,136
Capacity Revenue		13,807		—		—		13,807
Other Operating Revenue		87		1,324		248		1,659
Coal Sales (Third-Party)		—		30,185		—		30,185
Coal Sales (Intercompany)		—		24,589		(24,589)		—
Operating Revenues	$	86,030	$	56,098	$	(24,341)	$	117,787

Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues at March 31, 2024 (in thousands):


					Corporate and Other
Reconciliation of Revenue:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Delivered Energy	$	48,908	$	—	$	—	$	48,908
Capacity Revenue		11,773		—		—		11,773
Other Operating Revenue		157		810		296		1,263
Coal Sales (Third-Party)		—		49,630		—		49,630
Coal Sales (Intercompany)		—		16,406		(16,406)		—
Operating Revenues	$	60,838	$	66,846	$	(16,110)	$	111,574

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Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes at March 31, 2025 (in thousands):


					Corporate and Other
Reconciliation of Income (Loss) before Income Taxes:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Electric Operations — EBITDA Margin	$	26,143	$	—	$	23,417	$	49,560
Coal Operations — EBITDA Margin		—		5,689		(24,589)		(18,900)
Other Operating Revenue		87		1,324		248		1,659
Depreciation, Depletion and Amortization		(5,161)		(9,797)		(19)		(14,977)
Asset Retirement Obligations Accretion		(120)		(307)		—		(427)
Exploration Costs		—		(21)		—		(21)
Gain (loss) on disposal or abandonment of assets, net		—		21		—		21
Interest Expense		(1,732)		(1,991)		—		(3,723)
Equity Method Investment (Loss)		—		—		(236)		(236)
Corporate — General and Administrative		—		—		(2,977)		(2,977)
Income (Loss) before Income Taxes	$	19,217	$	(5,082)	$	(4,156)	$	9,979

Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes at March 31, 2024 (in thousands):


					Corporate and Other
Reconciliation of Income (Loss) before Income Taxes:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Electric Operations — EBITDA Margin	$	19,898	$	—	$	17,611	$	37,509
Coal Operations — EBITDA Margin		—		(1,205)		(16,406)		(17,611)
Other Operating Revenue		157		810		296		1,263
Depreciation, Depletion and Amortization		(4,697)		(10,728)		(18)		(15,443)
Asset Retirement Obligations Accretion		(111)		(288)		—		(399)
Exploration Costs		—		(70)		—		(70)
Gain (loss) on disposal or abandonment of assets, net		—		24		—		24
Interest Expense		(148)		(3,209)		(580)		(3,937)
Loss on Extinguishment of Debt		—		—		(853)		(853)
Equity Method Investment (Loss)		—		—		(249)		(249)
Corporate — General and Administrative		—		—		(2,448)		(2,448)
Corporate — Other Operating and Maintenance Costs		—		—		(92)		(92)
Income (Loss) before Income Taxes	$	15,099	$	(14,666)	$	(2,739)	$	(2,306)

Presented below are our Electric and Coal Operations assets and capital expenditures at March 31, 2025 (in thousands):


					Corporate and Other
Other Reconciliations:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Assets	$	222,865	$	141,023	$	2,209	$	366,097
Capital Expenditures	$	5,449	$	6,244	$	—	$	11,693

Presented below are our Electric and Coal Operations assets and capital expenditures at March 31, 2024 (in thousands):


					Corporate and Other
Other Reconciliations:	Electric Operations		Coal Operations		and Eliminations		Consolidated
Assets	$	211,116	$	370,292	$	4,012	$	585,420
Capital Expenditures	$	6,242	$	8,632	$	—	$	14,874

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(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 March 31,
	2025		2024
Basic earnings per common share:
Net income (loss) - basic	$	9,979	$	(1,696)
Weighted average shares outstanding - basic		42,619		34,816
Basic earnings (loss) per common share	$	0.23	$	(0.05)

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


	Three Months Ended March 31,
	2025		2024
Diluted earnings per common share:
Net income (loss) - diluted	$	9,979	$	(1,696)

Weighted average shares outstanding - basic		42,619		34,816
Add: Dilutive effects of Restricted Stock Units		843		—
Weighted average shares outstanding - diluted		43,462		34,816

Diluted net income (loss) per share	$	0.23	$	(0.05)

(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 and is in “Accounts payable and accrued liabilities” on our condensed consolidated balance sheets at March 31, 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 very pleased with our first quarter results. Building on the progress we made throughout 2024 in transitioning our company from a bituminous coal producer to an integrated independent power producer (“IPP”), our quarterly results showed the upside of this strategy and business model. As gas inventories dropped and colder weather prevailed, we benefitted from higher energy prices and delivered energy volumes during January and February. We also saw improvements in our coal production throughout the first three months of the year as our 2024 restructuring efforts continue to take hold. During the quarter, we generated $117.8 million of revenue generating $19.3 million of adjusted EBITDA, an improvement of $6.2 million and $12.5 million, respectively, over the same period a year ago.

The Company continued to leverage the strong relationships we built with multiple counterparties, allowing us to supplement periods of weaker pricing with limited sales of firm energy. These firm energy sales help to mitigate the impacts of inconsistent weather and fluctuating natural gas prices and allowed us to focus on maximizing the value of our Merom Power Plant in a way that balances challenging periods while also giving us flexibility to capture upside opportunity in periods of elevated pricing, like we saw throughout January and February.

With respect to our ongoing negotiations with a leading global data center developer for the supply of a significant portion of our plant's output of capacity and energy for well over a decade, we believe that we continue to make meaningful progress towards the execution of definitive agreements. Our partner has made substantial investment with Hallador through the purchase of an exclusivity agreement which we disclosed last quarter, and with other stakeholders through payments and agreements to secure land, transmission capacity and equipment in support of the potential transaction. As we have previously disclosed, the exclusivity period runs through the beginning of June 2025. As we also highlighted in previous disclosures, these types of deals are inherently complex and involve multiple parties, which adds time and alignment challenges to the negotiation process. Despite these challenges, we remain encouraged by our partners and the steady progress that we continue to make towards definitive agreements. That said, it is uncertain that the definitive agreements will be executed by the expiration of the current exclusivity period. We are presently evaluating our counterparty’s request to extend the exclusivity period versus entertaining other opportunities while concurrently moving our original deal forward on a non-exclusive basis. While we remain encouraged by our progress and still believe that our current development partner represents a tremendous long-term opportunity for our company and its shareholders, we would be remiss to ignore the high level of interest that we have seen from third parties that would like to discuss alternative opportunities if we are ultimately unable to finalize definitive agreements with our current partner. Taken as a whole, we firmly believe that, in the end, we will forge a strategic partnership that will create significant value for years to come.

In the past, we highlighted our belief that the prevailing industry trend of retiring dispatchable generators, including coal, in favor of non-dispatchable resources such as wind and solar will lead to an unbalanced energy equation and extended volatility in the energy markets. We believe this volatility has the potential to make the attributes of our subsidiary, Hallador Power, much more valuable due to the enhanced reliability we provide versus non-dispatchable generators. In light of this, we continue to evaluate how to further enhance this value. Consistent with this belief, we are actively seeking opportunities to acquire additional dispatchable generation, which should help diversify our risk and provide opportunities to upsize the strategic deals that we continue to evaluate. We believe that this approach enhances our financial flexibility and strengthens our position in the evolving energy market.

We continue to study the benefits of not only adding additional generation through acquisition or expansion, but the potential of enhancing the reliability, resiliency and flexibility of our current plant by adding natural gas co-firing and creating a dual fuel scenario. While we are still in the evaluation process, and we recognize the tremendous amount of work that is required to accomplish such a transition, by adding the capability to co-fire with gas or coal, we believe that it will lead to opportunities where the counterparty desires to limit the amount of coal fired electricity that they are purchasing, while also providing Hallador the ability to take advantage of the best fuel cost scenario and better control our operating expenses across multiple fuel scenarios. Additionally, we believe that the ability to co-fire with natural gas

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and/or coal will also provide increased resiliency in times where gas availability is limited, as we have seen in various winter storms across the last several years. This co-firing also allows us to retain the advantage of operating our Sunrise Coal subsidiary and leveraging our own coal supply to prevent unreasonable price increases by third party providers while simultaneously supporting our workforce and the surrounding community.

As we look to the future, our Merom Power Plant can produce up to 6 million MWh annually. The forward power price curves indicate that the margins earned on energy produced at Merom and the value of the accredited capacity sales assigned to the plant continue to increase, as we saw in the most recent MISO auction, where accredited capacity sold at prices in excess of $600 per MW Day in high demand seasons. We are seeing strong indications for both energy and capacity sales in 2025 and beyond and remain excited by our negotiations related to supporting data center development within the State of Indiana for many years to come.

We believe that our approach should allow Hallador Power to capture higher prices and energy volumes in the future versus what we have historically achieved since buying the plant in late 2022, specifically as we look to 2027 and beyond. Following the end of the quarter, we completed maintenance on one of the units at the plant and now have that unit back in service. We currently have a second unit out of service for scheduled maintenance and expect that unit to be back online early in the third quarter. We typically choose the shoulder season periods for these scheduled maintenance outages as power demand and pricing in spring are traditionally lower than in other parts of the year. We also try to limit our firm electricity sales during these periods to guard against any unforeseen or forced outages, which have the potential to expose us to spot market pricing. Despite these outages, we have contracted approximately 3.0 million MWh for the remainder of 2025 at an average price of $37.20/MWh, which should help to smooth our exposure to the spot market throughout the remainder of the year. For 2026, we currently have contracted 3.4 million MWh at an average sales price of $44.43/MWh and continue to see high demand. Following 2026, we are optimistic that we can sell energy at higher prices in support of data center development and/or to traditional wholesale customers in line with the indicators of a higher forward curve.

As we said on March investor call, we continue to evaluate other strategic transactions that could add durability, scale, and geographic expansion opportunities to our electric operations. We believe that Hallador is uniquely positioned to transform retiring and/or underperforming assets into future opportunities. This will enable us to supply high demand end users, such as data centers and on-shored industrial customers, with minimal impact to retail consumers. By continuing the operations of the dispatchable plants to support large load industrial users as the utilities transition to non-dispatchable generation, the new generation becomes additive to the struggling grid rather than cannibalizing the overall reliability of what exists today. We are optimistic about the potential to add to our strategic 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 continue our shift away from the less favorable pricing related to plant acquisition, to traditional wholesale market pricing, and ultimately to the enhanced pricing associated with supporting data centers and other large load end users. Importantly, the positive momentum that we are seeing from the current administrations on both the federal and state levels should make transactions of this sort more feasible than they would have been under the prior administrations.

Shifting to our coal operations, we continue to see improvements from the restructuring of our Sunrise Coal division that we initially announced in the first quarter of 2024. We spent much of last year optimizing production, headcount, and strategy to best support our electric operations and our existing third-party coal contracts. As we look to the future, this restructuring should provide us with greater flexibility to quickly scale if we see coal prices increase to a point that justifies restarting production at our more expensive units.

With renewed support of coal mining and coal fired power generation on both the federal and state level, we believe that we are positioned well to take advantage of opportunities for growth and/or expansion. Current market dynamics have improved over where they were last year, and if this trend continues, it has the potential to encourage us to bring on additional coal production in the back half of 2025 and/or 2026. Notwithstanding this potential to increase production, we currently expect to produce approximately 3.8 million tons of coal in 2025. In the first quarter of 2025, we produced approximately 1.0 million tons of coal at our Oaktown Mining Complex and shipped approximately 1.1 million tons to Merom and other customers. We use supplemental coal from third party suppliers typically purchased at favorable prices to diversify self-production supply risk and to provide us additional flexibility in our sales portfolio. The optionality to

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obtain low-cost tons either internally or from third parties while capturing upward swings in the commodity markets for coal should further maximize margins while optimizing fuels costs at Merom.

We remain excited about the continued and deliberate transformation of Hallador from a commodity focused producer of coal to an IPP. We believe this transition provides a significant opportunity to capture the expanding margins of the energy markets and capitalize on the soaring demand for electricity. We are pleased by the strong interest we continue to see from potential counterparties in our energy and capacity offerings, bolstered by Indiana’s efforts to attract data centers and other high-density power users through its business-friendly climate and favorable tax policies. The support of the coal industry by the Trump administration throughout the first quarter should also help to dampen the headwinds we were previously facing and provide flexibility as we continue our strategic transition in support of the economy’s insatiable appetite for reliable energy that we see advancing every day. We continue to believe that our business model positions us well to materially strengthen our opportunities for growth and cash flow generation.

Our goal is for Hallador Power to generate on average 1.5 million MWh on a quarterly basis, which equates to 6.0 million MWh annually (see Hallador Power’s capacity and utilization information below). During the first three months of the year, Hallador Power generated 1.4 million MWh, or 93.3% or our quarterly target and purchased 0.2 million MWh.


	Three Months Ended March 31,
	2025		2024
Power Capacity and Utilization
Nameplate capacity (MW)⁽ⁱ⁾	1,080		1,080
Accredited capacity for the period (MW)⁽ⁱⁱ⁾	845		836
Accredited capacity utilization⁽ⁱⁱⁱ⁾	78	%	45	%

(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 $56.0 million or 86.2% of our target with $45.5 million remaining to be delivered in 2025. We believe our forward Capacity sales goals are attainable as illustrated in our “Solid 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.

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OVERVIEW

The following is an overview our Electric Operations and Coal Operations for Q1 2025 compared to Q4 2024.

Q1 2025 Net Income of $10.0 million.

Electric Operations: During the first quarter of 2025, we sold 1.6 MWh representing a 23.1% increase in total MWh sold and an increase of $0.10 in operating revenues per MWh from the fourth quarter of 2024. This increase is primarily due to entering the winter season which has greater contracted delivered energy MWh than the fall season (Q4 2024).

In Q1 2025, Electric Operations operating revenues were $85.9 million, or $54.91 per MWh sold, on a segment basis.

ii.

In Q1 2025, Electric Operations fuel, other operating and maintenance and cost of purchased power were $49.4 million, or $31.59 per MWh compared to $41.1 million, or $32.34 per MWh in Q4 2024.

iii.

Q1 2025 Electric Operations income before income taxes was $12.27 per MWh, an increase of $4.02 from Q4 2024.

Coal Operations: During the first quarter of 2025, 1.1 million tons of coal were shipped on a segment basis during the quarter, with approximately 0.5 million tons of that being shipped to the Merom Power Plant for $24.6 million. This is an increase of 0.2 million tons of coal shipped from Q4 2024, on a segment basis. This increase in coal shipments is mainly driven by an increase in shipments to our Merom Power Plant and a new coal contract.

In Q1 2025, Coal Operations operating revenues were $54.8 million, or $51.14 per ton, on a segment basis an increase of $5.55 per ton from Q4 2024. This increase is a result of new coal contract terms.

ii.

In Q1 2025, Hallador’s Coal Operations other operating and maintenance costs were $23.9 million, or $22.27 per ton, compared to $8.9 million, or $10.13 per ton, on a segment basis, in Q4 2024. This change is due to certain reclassifications made as of Q4 2024 for the entirety of 2024 that reduced “other operating and maintenance costs” and increased “depreciation, depletion and amortization”. This reclassification totaled $8.0 million of which $6.4 million related to the first three quarters of 2024.

iii.

We recorded a loss before income taxes for the quarter of $5.98 per ton on a segment basis. This is a decrease in our loss of $257.11 per ton from Q4 2024 income from operations.

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II.

Solid Forward Sales Position (unaudited)


	2025		2026		2027		2028		2029		Total
Power
Energy
Contracted MWh (in millions)		3.04		3.36		1.78		1.09		0.27		9.54
Average contracted price per MWh	$	37.20	$	44.43	$	54.66	$	52.94	$	51.33
Contracted revenue (in millions)	$	113.09	$	149.28	$	97.29	$	57.70	$	13.86	$	431.22

Capacity
Average daily contracted capacity MW		784		733		623		454		100
Average contracted capacity price per MWd	$	211	$	230	$	226	$	225	$	230
Contracted capacity revenue (in millions)	$	45.45	$	61.54	$	51.40	$	37.33	$	3.47	$	199.19

Total Energy & Capacity Revenue

Contracted Power revenue (in millions)	$	158.54	$	210.82	$	148.69	$	95.03	$	17.33	$	630.41

Coal
Priced tons - 3rd party (in millions)		2.21		2.50		2.50		0.50		—		7.71
Avg price per ton - 3rd party	$	50.95	$	55.49	$	56.74	$	59.00	$	—
Contracted coal revenue - 3rd party (in millions)	$	112.60	$	138.73	$	141.85	$	29.50	$	—	$	422.68

TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED	$	271.14	$	349.55	$	290.54	$	124.53	$	17.33	$	1,053.09

Priced tons - Intercompany (in millions)		1.82		2.30		2.30		2.30		—		8.72
Avg price per ton - Intercompany	$	51.00	$	51.00	$	51.00	$	51.00	$	—
Contracted coal revenue - Intercompany (in millions)	$	92.82	$	117.30	$	117.30	$	117.30	$	—	$	444.72

TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT	$	363.96	$	466.85	$	407.84	$	241.83	$	17.33	$	1,497.81

●

Actual revenue related to solid forward sales positions may differ materially for various reasons, including price adjustment features for coal quality and cost escalations, volume optionality provisions and potential force majeure events.

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LIQUIDITY AND CAPITAL RESOURCES

Liquidity and Capital Resources

As set forth in our condensed consolidated statements of cash flows, cash provided by operations was $38.4 million and $16.4 million for the three months ended March 31, 2025 and 2024, respectively.

Bank debt was reduced by $21.0 million during the three months ended March 31, 2025. As of March 31, 2025, our bank debt was $23.0 million.

We expect cash generated from operations to primarily fund our capital expenditures and our debt service. As of March 31, 2025, we also had an additional borrowing capacity of $52.8 million.

Total liquidity as of March 31, 2025 was $69.0 million.

II.

Material Off-Balance Sheet Arrangements

Other than our surety bonds for reclamation, we have no material off-balance sheet arrangements. We have recorded the present value of reclamation obligations of $17.1 million, including $5.8 million at Merom, presented as asset retirement obligations (“ARO”) and accounts payable and accrued liabilities in our accompanying condensed consolidated balance sheets. In the event we are not able to perform reclamation, we have surety bonds in place totaling $30.9 million to cover ARO.

CAPITAL EXPENDITURES (capex)

For the three months ended March 31, 2025, capex was $11.7 million allocated as follows (in millions):


Oaktown – maintenance capex	$	4.0
Oaktown – investment		2.2
Merom Plant		5.5
Capex per the Condensed Consolidated Statements of Cash Flows	$	11.7

RESULTS OF OPERATIONS

Presentation of Segment Information

Our operations are divided into two primary reportable segments: Electric Operations and Coal Operations. The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are presented as “Corporate and Other and Eliminations” within the Notes to the Condensed Consolidated Financial Statements and primarily are comprised of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana and Oaktown Gas, LLC, which we account for using the equity method.

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Electric Operations


	Three Months Ended March 31,
	2025		2024

	(in thousands)
Delivered Energy	$	72,136	$	48,908
Capacity Revenue		13,807		11,773
Electric Sales	$	85,943	$	60,681

Fuel	$	(38,071)	$	(24,435)
Other Operating Costs (1)		(8)		(493)
Other Operating and Maintenance Costs (2)		(4,527)		(4,886)
Cost of Purchased Power		(6,840)		(1,926)
Utilities		(676)		(302)
Labor		(8,143)		(7,683)
General and Administrative		(1,535)		(1,058)
EBITDA Margin		26,143		19,898
Other Operating Revenue		87		157
Depreciation, Depletion and Amortization		(5,161)		(4,697)
Asset Retirement Obligations Accretion		(120)		(111)
Interest expense		(1,732)		(148)
Income (Loss) before Income Taxes	$	19,217	$	15,099

(1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.

(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).


	Three Months Ended March 31,
	2025		2024

	(per MWh)
MWh Generated (in thousands)		1,422		816
MWh Purchased (in thousands)		143		75
MWh Sold (in thousands)		1,565		891

Delivered Energy	$	46.09	$	54.89
Capacity Revenue		8.82		13.21
Electric Sales	$	54.91	$	68.10

Fuel	$	(24.33)	$	(27.42)
Other Operating Costs (1)		(0.01)		(0.55)
Other Operating and Maintenance Costs (2)		(2.89)		(5.48)
Cost of Purchased Power		(4.37)		(2.16)
Utilities		(0.43)		(0.34)
Labor		(5.20)		(8.62)
General and Administrative		(0.98)		(1.19)
EBITDA Margin		16.70		22.34
Other Operating Revenue		0.06		0.18
Depreciation, Depletion and Amortization		(3.30)		(5.27)
Asset Retirement Obligations Accretion		(0.08)		(0.12)
Interest expense		(1.11)		(0.17)
Income (Loss) before Income Taxes	$	12.27	$	16.96

(1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.

(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).

Q1 2025 vs. Q1 2024

Delivered Energy increased $23.2 million, or 47.5%, and we sold 0.7 million MWh more than we did in Q1 2024. These increases were due to $26.4 million in new revenue contracts starting in Q1 2025 that were not in effect during Q1 2024. During the quarter we experienced a significantly higher priced natural gas environment when compared to Q1 2024,

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(average spot price for natural gas was up $2.02 per mbtu, or 94.7%, compared to Q1 2024). As natural gas is a competitor to coal, this price increase helped drive up the demand for Power during Q1 2025.

Fuel increased $13.6 million, or 55.8%, compared to the first quarter of 2024. Our generated MWh’s increased by 0.6 million MWh, or 74.3%, from the first quarter of 2024. We used 0.2 million tons, or 61.2%, more in production compared to the prior year. These increases were primarily related to our increased electricity sales which were partially offset by declines in coal market pricing. The average purchase price per ton of coal used in the plant on a segment basis, was $53.80 in the first quarter of 2025, decreasing from $57.45 per ton in the first quarter of 2024.

Cost of purchased power was $4.9 million during the first quarter of 2025. When energy hours at the Merom Hub are priced below our production cost or during outages at our Merom Facility, we have the option to make net hourly purchases of power in the MISO market, which we record as cost of purchased power. During the first quarter of 2025, we purchased 0.2 million MWh, an increase of 90.7% from Q1 2024, at an average price of $47.83 per MWh.

Interest expenses increased $1.6 million, or 1070.3%, compared to the first quarter of 2024. The increase in our interest expense primarily relates $1.2 million of accretion related to our to a prepaid delivered energy contract.

Income before income taxes increased $4.1 million, or 27.3%, compared to the first quarter of 2024. The main drivers of this change in income before income taxes are described in the discussion above.

Coal Operations


	Three Months Ended March 31,
	2025		2024

	(in thousands)
Coal Sales	$	54,774	$	66,036

Fuel	$	556	$	1,235
Other Operating and Maintenance Costs		23,854		31,791
Utilities		3,476		4,292
Labor		18,886		27,485
General and Administrative		2,313		2,438
EBITDA Margin		5,689		(1,205)
Other Operating Revenue		1,324		810
Depreciation, Depletion and Amortization		(9,797)		(10,728)
Asset Retirement Obligations Accretion		(307)		(288)
Exploration Costs		(21)		(70)
Gain (loss) on disposal or abandonment of assets, net		21		—
Interest expense		(1,991)		(3,209)
Income (Loss) before Income Taxes	$	(5,082)	$	(14,690)


	Three Months Ended March 31,
	2025		2024

	(per ton)
Tons Sold		1,071		1,214

Coal Sales	$	51.14	$	54.40

Fuel	$	0.52	$	1.02
Other Operating and Maintenance Costs		22.27		26.19
Utilities		3.25		3.54
Labor		17.63		22.64
General and Administrative		2.16		2.01
EBITDA Margin		5.31		(0.99)
Other Operating Revenue
Depreciation, Depletion and Amortization		(9.15)		(8.84)
Asset Retirement Obligations Accretion		(0.29)		(0.24)
Exploration Costs		(0.02)		(0.06)
Gain (loss) on disposal or abandonment of assets, net		0.02		—
Interest expense		(1.86)		(2.64)
Income (Loss) before Income Taxes	$	(5.98)	$	(12.77)

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Q1 2025 vs. Q1 2024

Coal sales decreased $11.3 million, or 17.1%, compared to the first quarter of 2024. Consolidated coal sales decreased $19.4 million, or 39.2%, from 2024. These declines were due to reductions in volume and average sales price for our coal. Our average sales price, on a segment basis, decreased $3.25 per ton and we sold 0.1 million tons less compared to 2024. Our average sales price, on a consolidated basis, for 2025 decreased $4.22 per ton and we sold 0.3 million tons less compared to 2024. Operating revenues for the first quarter of 2025 include $24.6 million in sales to the Merom plant which were eliminated in the consolidation.

Other operating and maintenance costs decreased $7.9 million, or 25.0%, compared to the first quarter of 2024. During the first quarter of 2025, we produced 0.3 million tons less on a segment basis than 2024. Labor decreased $8.6 million, or 31.3%, from 2024, and decreased $5.01 per ton sold. These changes were driven by the Reorganization Plan disclosed in “Note 13 — Organizational Restructuring” to the condensed consolidated financial statements. As part of the Organizational Restructuring, we incurred aggregate expenses of $1.1 million in the first quarter of 2024 that were included in coal operations “Labor”. These charges related to compensation, tax, professional, and insurance related expenses and are considered one-time charges paid during 2024. Additionally, we went from 5 mines producing to 1 mine producing and reduced our coal employee headcount by 201 employees.

Interest expense decreased $1.2 million, or 38.0%, compared to the first quarter of 2024. Our decreased interest expense relates to reductions of convertible debt of $11.0 million, related party debt of $5.0 million and bank debt of $54.0 million, from Q1 2024.

Loss before income taxes decreased $9.6 million, or 65.4%, compared to the first quarter of 2024. The main drivers of this change in loss before income taxes are described in the discussion above.

Quarterly coal sales and cost data on a segment basis are as follows (in thousands, except per ton data and wash plant recovery percentage):


All Mines	2nd 2024			3rd 2024			4th 2024			1st 2025			T4Qs
Tons produced		889			873			971			1,020			3,753
Tons sold		849			926			875			1,071			3,721
Wash plant recovery in %		59	%		60	%		62	%		64	%
Capex (Coal Operations)	$	7,560		$	6,810		$	11,079		$	6,244		$	31,693
Maintenance capex (Coal Operations)	$	6,014		$	4,208		$	4,492		$	4,000		$	18,714
Maintenance capex per ton sold (Coal Operations)	$	7.08		$	4.54		$	5.13		$	3.73		$	5.03

Average cost per ton sold⁽ⁱ⁾	$	49.94		$	52.22		$	43.25		$	43.65


All Mines	2nd 2023			3rd 2023			4th 2023			1st 2024			T4Qs
Tons produced		1,723			1,594			1,331			1,271			5,919
Tons sold		1,714			2,054			1,461			1,214			6,443
Wash plant recovery in %		67	%		65	%		62	%		60	%
Capex (Coal Operations)	$	14,445		$	11,570		$	17,867		$	8,632		$	52,514
Maintenance capex (Coal Operations)	$	9,754		$	7,938		$	13,567		$	8,085		$	39,344
Maintenance capex per ton (Coal Operations)	$	5.69		$	3.86		$	9.29		$	6.66		$	6.11

Average cost per ton sold⁽ⁱ⁾	$	41.52		$	46.54		$	53.78		$	51.65

(i) Average cost per ton sold is calculated as the sum of the Coal Operation’s “Fuel”, “Other Operating and Maintenance Costs”, “Utilities” and “Labor” costs. Coal Operations costs are presented in the “Presentation of Segment Information” above.

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Presentation of Consolidated Information

EARNINGS (LOSS) PER SHARE


	2nd 2024		3rd 2024		4th 2024		1st 2025
Basic	$	(0.27)	$	0.04	$	(5.06)	$	0.23
Diluted	$	(0.27)	$	0.04	$	(5.06)	$	0.23


	2nd 2023		3rd 2023		4th 2023		1st 2024
Basic	$	0.51	$	0.49	$	(0.31)	$	(0.05)
Diluted	$	0.47	$	0.44	$	(0.31)	$	(0.05)

INCOME TAXES

Our effective tax rate (ETR) is estimated at ~0% and ~26% for the three months ended March 31, 2025 and 2024, respectively. For the three months ended March 31, 2025, we estimated our annual ETR based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate. Our ETR differs from the statutory rate due primarily to statutory depletion in excess of tax basis and changes in the valuation allowance. The deduction for statutory percentage depletion does not necessarily change proportionately to changes in income (loss) before income taxes.

RESTRICTED STOCK GRANTS

See “Item 1. Financial Statements - Note 9 - Stock Compensation Plans” for a discussion of RSUs.

CRITICAL ACCOUNTING ESTIMATES

We believe that the estimates of coal reserves, asset retirement obligation liabilities, deferred tax accounts, valuation of inventory, and the estimates used in impairment analysis are our critical accounting estimates.

The reserve estimates are used in the depreciation, depletion, and amortization calculations and our internal cash flow projections. If these estimates turn out to be materially under or over-stated, our depreciation, depletion and amortization expense and impairment test may be affected. The process of estimating reserves is complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. The reserve estimates are prepared by professional engineers, both internal and external, and are subject to change over time as more data becomes available. Changes in the reserves estimates from the prior year were nominal.

SMCRA and similar state statutes require, among other things, that surface disturbance be restored in accordance with specified standards and approved reclamation plans. SMCRA requires us to restore affected surface areas to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations.

Obligations are reflected at the present value of their future cash flows. We reflect accretion of the obligations for the period from the date they are incurred through the date they are extinguished. The ARO assets are amortized using the units-of-production method over estimated recoverable (proven and probable) reserves. We use credit-adjusted risk-free discount rates ranging from 7% to 10% to discount the obligation, inflation rates anticipated during the time to reclamation, and cost estimates prepared by its engineers inclusive of market risk premiums. Activities include reclamation of pit and support acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and slurry ponds.

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Accretion expense is recognized on the obligation through the expected settlement date. On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing and extent of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Any difference between the recorded amount of the liability and the actual cost of reclamation will be recognized as a gain or loss when the obligation is settled.

We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. We believe that our income tax filing positions and deductions would be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position. We have not taken any significant uncertain tax positions, and our tax provisions and returns are prepared by a large public accounting firm with significant experience in energy related industries. Changes to the estimates from reported amounts in the prior year were not significant.

Inventory is valued at a lower of cost or net realizable value (NRV). Anticipated utilization of low sulfur, higher-cost coal from our Freelandville, and Prosperity mines has the potential to create NRV adjustments as our estimated needs change. The NRV adjustments are subject to change as our costs may fluctuate due to higher or lower production and our NRV may fluctuate based on sales contracts we enter into from time to time. As of March 31, 2025, and December 31, 2024, coal inventory includes NRV adjustments of $0.1 million and $0.3 million, respectively.

Long-lived assets used in operations are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The determination of the lowest level of cash flows is largely based on nature of production, common infrastructure, common sales points, common regulation and management oversight to make such determinations. These determinations could impact the determination and measurement of a potential asset impairment. Management evaluates assets for impairment through an established process in which changes to significant assumptions such as prices, volumes and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future volumes, commodity prices, operating costs and capital investment plans, considering all available information at the date of review. Changes to any of the market-based assumptions can significantly affect estimates of undiscounted and discounted pre-tax cash flows and impact the recognition and amount of impairments.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

No material changes from the disclosure in our 2024 Annual Report on Form 10-K.

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ITEM 4. CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS

We maintain a system of disclosure controls and procedures that are designed for the purpose of ensuring that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our CEO and CFO and as appropriate to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our CEO and CFO of the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective.

There have been no changes to our internal control over financial reporting during the quarter ended March 31, 2025, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” These statements are based on our beliefs as well as assumptions made by, and information currently available to us. When used in this document, the words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “may,” “project,” “will,” and similar expressions identify forward-looking statements. Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements. These statements reflect our current views with respect to future events and are subject to numerous assumptions that we believe are open to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ from those in the forward-looking statements are:

●

changes in macroeconomic and market conditions and market volatility, and the impact of such changes and volatility on our financial position;

●

fluctuations in weather, gas and electricity commodity costs, inflation and economic conditions impact demand of our customers and our operating results;

●

the outcome or escalation of current hostilities in Ukraine and Israel;

●

changes in competition in electricity or coal markets and our ability to respond to such changes;

●

changes in coal prices, demand, and availability which could affect our operating results and cash flows;

●

risks associated with the expansion of our operations and properties;

●

legislation, regulations, administrative actions (e.g., Executive Orders), and court decisions and interpretations thereof, including those relating to the environment and the release of greenhouse gases, mining, miner health and safety, and health care, as well as those relating to data privacy protection;

●

deregulation of the electric utility industry or the effects of any adverse change in the coal industry, electric utility industry, or general economic conditions;

●

dependence on significant or long-term customer contracts, including renewing customer contracts upon expiration of existing contracts;

●

changing global economic conditions or the geopolitical environment in industries in which our customers operate;

●

anticipated changes in the U.S. political environment, including those resulting from the change in Presidential Administration and control of Congress, and to regulatory agencies;

●

changes in attitude toward environmental, social, and governance (“ESG”) matters among regulators, investors and parties with which we do business;

●

the effect of changes in taxes or tariffs and other trade measures;

●

risks relating to inflation and increasing interest rates;

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●

liquidity constraints, including due to restrictions contained in our indebtedness and those resulting from any future unavailability of financing;

●

customer bankruptcies, a decline in customer creditworthiness, or customer cancellations or breaches to existing contracts, or other failures to perform;

●

customer delays, failure to take coal under contracts or defaults in making payments;

●

adjustments made in price, volume or terms to existing coal supply and customer agreements;

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our productivity levels and margins earned on our coal or electricity sales;

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supply chain disruptions and changes in equipment, raw material, service or labor costs or availability, including due to inflationary pressures;

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changes in the availability of skilled labor;

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our ability to maintain satisfactory relations with our employees;

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increases in labor costs, adverse changes in work rules, or cash payments or projections associated with workers’ compensation claims;

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increases in transportation costs and risk of transportation delays or interruptions;

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operational interruptions due to geologic, permitting, labor, weather-related or other factors;

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risks associated with major mine-related or other accidents, mine fires, mine floods or other interruptions, including unanticipated operating conditions and other events that are not within our control;

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results of litigation, including claims not yet asserted;

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difficulty maintaining our surety bonds for mine reclamation;

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decline in or change in the coal industry’s share of electricity generation, including as a result of environmental concerns related to coal mining and combustion and the cost and perceived benefits of other sources of electricity, such as natural gas, nuclear energy, and renewable fuels;

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risks resulting from climate change or natural disasters;

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difficulty in making accurate assumptions and projections regarding post-mine reclamation;

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uncertainties in estimating and replacing our coal reserves;

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the impact of current and potential changes to federal or state tax rules and regulations, including a loss or reduction of benefits from certain tax deductions and credits;

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difficulty obtaining commercial property insurance;

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evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions;

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difficulty in making accurate assumptions and projections regarding future revenues and costs associated with equity investments in companies we do not control;

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the severity, magnitude and duration of any future pandemics, including impacts of the pandemic and of businesses’ and governments’ responses to the pandemic on our operations and personnel, and on demand for coal, the financial condition of our customers and suppliers, available liquidity and capital sources and broader economic disruptions; and

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other factors, including those discussed in “Item 1A. Risk Factors” in our Annual Report on Form 10-K.

If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement. When considering forward-looking statements, you should also keep in mind the risk factors described in “Item 1A. Risk Factors” in our Annual Report on Form 10-K. The risk factors could also cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments, unless required by law.

You should consider the information above when reading any forward-looking statements contained in this Quarterly Report on Form 10-Q; other reports filed by us with the U.S. Securities and Exchange Commission (“SEC”); our press releases; our website www.halladorenergy.com and written or oral statements made by us or any of our officers or other authorized persons acting on our behalf.

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PART II - OTHER INFORMATION

ITEM 4. MINE SAFETY DISCLOSURES

See Exhibit 95.1 to this Form 10-Q for a listing of our mine safety violations.

ITEM 6. EXHIBITS


Exhibit No.		Document
31.1		SOX 302 Certification - Chief Executive Officer
31.2		SOX 302 Certification - Chief Financial Officer
32		SOX 906 Certification
95.1		Mine Safety Disclosures
97.1		Hallador Energy Company Policy for the Recovery of Erroneously Awarded Compensation (incorporated by reference to Exhibit 97.1 to the Form 10-K filed March 14, 2024)
101.INS		Inline XBRL Instance Document
101.SCH		Inline XBRL Schema Document
101.CAL		Inline XBRL Calculation Linkbase Document
101.LAB		Inline XBRL Labels Linkbase Document
101.PRE		Inline XBRL Presentation Linkbase Document
101.DEF		Inline XBRL Definition Linkbase Document
104		Cover Page Interactive Data File (embedded with the Inline XBRL document)

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	HALLADOR ENERGY COMPANY

Date: May 12, 2025	/s/ MARJORIE HARGRAVE
	Marjorie Hargrave, CFO (Principal Financial Officer and Principal Accounting Officer)