Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2025
OR
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number:001-34743
HALLADOR ENERGY COMPANY
(www.halladorenergy.com)
Colorado
84-1014610
(State of incorporation)
(IRS Employer Identification No.)
1183 East Canvasback Drive, Terre Haute, Indiana
47802
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code: 812.299.2800
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol
Name of each exchange on which registered
Common Shares, $.01 par value
HNRG
Nasdaq
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulations S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☐
Accelerated filer ☑
Non-accelerated filer ☐
Smaller reporting company ☑
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
As of November 3, 2025, we had 43,825,006 shares of common stock outstanding.
TABLE OF CONTENTS
PART I - FINANCIAL INFORMATION
1
ITEM 1. FINANCIAL STATEMENTS (Unaudited)
Condensed Consolidated Balance Sheets
Condensed Consolidated Statements of Operations
2
Condensed Consolidated Statements of Cash Flows
3
Condensed Consolidated Statements of Stockholders’ Equity
4
Notes to Condensed Consolidated Financial Statements
5
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
21
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
34
ITEM 4. CONTROLS AND PROCEDURES
PART II - OTHER INFORMATION
36
ITEM 1A. RISK FACTORS
ITEM 4. MINE SAFETY DISCLOSURES
ITEM 6. EXHIBITS
37
SIGNATURES
38
ITEM 1. FINANCIAL STATEMENTS
Hallador Energy Company
(in thousands, except per share data)
(unaudited)
September 30,
December 31,
2025
2024
ASSETS
Current assets:
Cash and cash equivalents
$
12,663
7,232
Restricted cash
22,819
4,921
Accounts receivable
24,763
15,438
Inventory
28,006
36,685
Parts and supplies
44,002
39,104
Prepaid expenses
4,293
1,478
Total current assets
136,546
104,858
Property, plant and equipment:
Land and mineral rights
69,961
70,307
Buildings and equipment
454,040
429,857
Mine development
99,852
92,458
Finance lease right-of-use assets
13,034
Total property, plant and equipment
636,887
605,656
Less - accumulated depreciation, depletion and amortization
(370,903)
(347,952)
Total property, plant and equipment, net
265,984
257,704
Equity method investments
2,713
2,607
Other assets
4,218
3,951
Total assets
409,461
369,120
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of bank debt, net
42,698
4,095
Accounts payable and accrued liabilities
44,010
44,298
Current portion of lease financing
7,395
6,912
Contract liabilities - current
113,244
97,598
Total current liabilities
207,347
152,903
Long-term liabilities:
Bank debt, net
—
37,394
Long-term lease financing
3,140
8,749
Asset retirement obligations
16,268
14,957
Contract liabilities - long-term
34,362
49,121
Other
2,156
1,711
Total long-term liabilities
55,926
111,932
Total liabilities
263,273
264,835
Commitments and contingencies (Note 16)
Stockholders' equity:
Preferred stock, $.10 par value, 10,000 shares authorized; none issued
Common stock, $.01 par value, 100,000 shares authorized; 42,978 and 42,621 issued and outstanding, as of September 30, 2025 and December 31, 2024, respectively
430
426
Additional paid-in capital
189,086
189,298
Retained deficit
(43,328)
(85,439)
Total stockholders’ equity
146,188
104,285
Total liabilities and stockholders’ equity
See accompanying notes to the condensed consolidated financial statements.
Three Months Ended September 30,
Nine Months Ended September 30,
SALES AND OPERATING REVENUES:
Electric sales
93,235
72,116
239,154
192,996
Coal sales
51,256
31,662
119,588
114,093
Other revenues
2,355
1,377
8,780
3,685
Total sales and operating revenues
146,846
105,155
367,522
310,774
EXPENSES:
Fuel
27,119
13,755
57,392
34,684
Other operating and maintenance costs
44,415
32,741
101,759
103,704
Cost of purchased power
2,074
3,149
11,086
7,694
Utilities
4,543
3,586
13,202
12,090
Labor
27,574
26,721
81,402
88,444
Depreciation, depletion and amortization
9,142
13,838
29,661
42,930
Asset retirement obligations accretion
446
410
1,310
1,208
Exploration costs
62
157
179
General and administrative
4,770
6,471
19,096
20,218
Gain on disposal or abandonment of assets, net
(2,334)
(290)
(2,410)
(536)
Total operating expenses
117,787
100,443
312,655
310,615
INCOME FROM OPERATIONS
29,059
4,712
54,867
159
Interest expense (1)
(4,927)
(2,692)
(12,469)
(10,364)
Loss on extinguishment of debt
(2,790)
Equity method investment (loss)
(248)
(234)
(287)
(740)
NET INCOME (LOSS) BEFORE INCOME TAXES
23,884
1,786
42,111
(13,735)
INCOME TAX EXPENSE (BENEFIT):
Current
Deferred
232
(3,389)
Total income tax expense (benefit)
NET INCOME (LOSS)
1,554
(10,346)
NET INCOME (LOSS) PER SHARE:
Basic
0.56
0.04
0.98
(0.27)
Diluted
0.55
0.97
WEIGHTED AVERAGE SHARES OUTSTANDING
43,007
42,598
42,869
38,455
43,434
43,018
43,287
(1) Interest Expense:
Interest on bank debt
1,763
2,073
4,661
7,657
Other interest
2,585
181
6,208
1,456
Amortization of debt issuance costs
579
438
1,600
1,251
Total interest expense
4,927
2,692
12,469
10,364
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax (benefit)
Equity method investment loss
287
740
2,790
Cash paid on asset retirement obligation reclamation
(455)
(820)
Stock-based compensation
2,144
3,320
Amortization of contract liabilities
(82,639)
(59,236)
Accretion on contract liabilities
5,659
274
1,352
Change in current assets and liabilities:
(9,325)
8,029
8,679
(8,002)
(4,898)
(786)
1,190
(1,098)
1,923
(7,715)
Contract liabilities
77,867
57,293
Net cash provided by operating activities
72,978
26,985
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures
(44,277)
(39,606)
Proceeds from sale of equipment
2,891
3,373
Investment in equity method investments
(394)
Net cash used in investing activities
(41,780)
(36,233)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on bank debt
(63,000)
(86,500)
Borrowings of bank debt
63,000
65,000
Payments on lease financing
(5,187)
(4,105)
Proceeds from sale and leaseback arrangement
3,783
Issuance of related party notes payable
5,000
Payments on related party notes payable
(5,000)
Debt issuance costs
(330)
(654)
ATM offering
34,515
Taxes paid on vesting of RSUs
(2,352)
(273)
Net cash (used in) provided by financing activities
(7,869)
11,766
Increase in cash, cash equivalents, and restricted cash
23,329
2,518
Cash, cash equivalents, and restricted cash, beginning of period
12,153
7,123
Cash, cash equivalents, and restricted cash, end of period
35,482
9,641
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH:
3,829
5,812
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest
4,718
SUPPLEMENTAL NON-CASH FLOW INFORMATION:
Change in capital expenditures included in accounts payable and prepaid expense
(5,855)
(7,825)
Stock issued on redemption of convertible notes and interest
22,993
Additional
Total
Common Stock Issued
Paid-in
Retained
Stockholders’
Shares
Amount
Capital
Deficit
Equity
Balance, June 30, 2025
42,978
188,935
(67,212)
122,153
585
Stock issued on vesting of RSUs
64
(1)
(28)
(433)
(434)
Net Income
Balance, September 30, 2025
43,014
Balance, December 31, 2024
42,621
577
6
(6)
(184)
(2)
(2,350)
Earnings
Balance, June 30, 2024
42,599
186,945
128,799
316,170
1,073
Net income
Balance, September 30, 2024
188,018
130,353
318,797
Balance, December 31, 2023
34,052
341
127,548
140,699
268,588
379
(4)
(159)
(271)
Stock issued on redemption of convertible notes
3,672
22,957
Stock issued in ATM offering
4,655
47
34,468
Net loss
GENERAL BUSINESS
The condensed consolidated financial statements include the accounts of Hallador Energy Company (hereinafter known as “we, us, or our”) and its wholly owned subsidiaries Hallador Power Company, LLC (“Hallador Power”), Sunrise Coal, LLC (“Sunrise”), and Hourglass Sands, LLC (“Hourglass”), as well as Hallador Power and Sunrise’s wholly owned subsidiaries.
Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The Chief Operating Decision Maker (“CODM”), who is the Company’s Chief Executive Officer, reviews and assesses operating performance measures related to our Electric Operations and our Coal Operations segments.
In addition to these reportable segments, the Company has a “Corporate and Other and Eliminations” category, which is not significant enough, on a stand-alone basis, to be considered an operating segment. Corporate and Other and Eliminations primarily consist of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, LLC (“Sunrise Energy”), a private gas exploration company with operations in Indiana and Oaktown Gas, LLC, which we account for using the equity method.
The Electric Operations reportable segment includes electric power generation facilities of the Merom Power Plant (“Merom”).
The Coal Operations reportable segment includes our currently operating underground mining complex Oaktown 1. We have other mining complexes and locations which were idled during the year ended December 31, 2024.
All significant intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to the Company’s prior period condensed consolidated financial information to conform to the current period presentation. These presentation changes did not impact the Company’s condensed consolidated net income (loss), consolidated cash flows, total assets, total liabilities or total stockholders’ equity.
The interim financial data is unaudited; however, in our opinion, it includes all adjustments, consisting only of normal recurring adjustments necessary for a fair statement of the results for the interim periods. The condensed consolidated financial statements included herein have been prepared pursuant to the Securities and Exchange Commission’s (the “SEC”) rules and regulations; accordingly, certain information and footnote disclosures normally included in generally accepted accounting principles (“GAAP”) financial statements have been condensed or omitted.
The results of operations and cash flows for the three and nine months ended September 30, 2025, are not necessarily indicative of the results to be expected for future quarters or for the year ending December 31, 2025.
Our organization and business, the accounting policies we follow, and other information are contained in the notes to our consolidated financial statements filed as part of our 2024 Annual Report on Form 10-K. This quarterly report should be read in conjunction with such Annual Report on Form 10-K.
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.
Recent Accounting Pronouncements – Not Yet Adopted
In December 2023, the Financial Accounting Standards Board ("FASB") issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures ("ASU 2023-09"). ASU 2023-09 primarily requires enhanced disclosures to (1) disclose specific categories in the rate reconciliation, (2) disclose the amount of income taxes paid and expensed disaggregated by federal, state, and foreign taxes, with further disaggregation by individual jurisdictions if certain criteria are met, and (3) disclose income (loss) from continuing operations before income tax (benefit) disaggregated between domestic and foreign. ASU 2023-09 is effective for fiscal years beginning after December 15, 2024, with early adoption permitted. We are currently evaluating the impact of adopting ASU 2023-09, but do not expect it to have a material effect on our consolidated financial statements.
In November 2024, the FASB issued ASU 2024-04, Debt - Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversion of Convertible Debt Instruments. The objective of the standard is to improve the relevance and consistency in application of the induced conversion guidance in Subtopic 470-20, Debt with Conversion and Other Options. This standard will affect entities that settle convertible debt instruments for which the conversion privileges are changed to induce conversion. The guidance will be effective for annual reporting periods beginning after December 15, 2025, and interim reporting periods within those annual reporting periods. The Company is currently evaluating the impact of the new standard on its financial statements and related disclosures.
In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting-Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard update improves the disclosures about a public business entity’s expenses by requiring more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation and amortization) included within income statement expense captions. The guidance will be effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. The Company is currently evaluating the impact of adoption of the standard on its financial statement disclosures.
(3)
LONG-LIVED ASSET IMPAIRMENTS
During the year ended December 31, 2024, the Company recorded a $215.1 million non-cash impairment charge in our Coal Operations segment due to the results of our annual business plan review. As part of that business plan review, the Company evaluated core hole samples at several of our mines, noting the samples obtained at our Oaktown 2 mine were determined to be of a lower quality and density than that of the Oaktown 1 mine. As such, the Company decided to temporarily seal the Oaktown 2 mine, and to focus coal production at the Oaktown 1 mine, which has lower recovery costs.
The fair values of the impaired assets were determined using a discounted cash flow model, which represents Level 3 fair value measurements under the fair value hierarchy. The fair value analysis used assumptions regarding the projected economics of the Coal Operations assets, given prevailing commodity prices and operating expense levels.
For the three and nine months ended September 30, 2025, no impairment charges were recorded for long-lived assets.
INVENTORY
Inventory is valued at a lower of cost or net realizable value (“NRV”). As of September 30, 2025, and December 31, 2024, coal inventory includes NRV adjustments of $0.1 million and $0.3 million, respectively. During the quarter, as part of the Company’s routine inventory reconciliation process, a downward adjustment of $2.6 million was recorded to coal inventory.
(5)
BANK DEBT
On June 27, 2025, the Company executed the Third Amendment (“Third Amendment”) to the Fourth Amended and Restated Credit Agreement, dated as of August 2, 2023 (as amended, the “Credit Agreement”), with PNC Bank, National Association (in its capacity as administrative agent, "PNC"), which was accounted for as a debt modification. The primary purpose of the Third Amendment was to provide additional operating flexibility for the remainder of 2025 by redefining covenants, deferring certain covenants until the third quarter of 2025 and moving our October 2025 payment to January 2026. The Third Amendment provides for additional flexibility for the Company to enter into prepaid forward power sale contracts, provided that the Company maintains one hundred percent of the outstanding aggregate principal balance of the Credit Agreement (“Term Loan”) as a compensating balance. During the second quarter of 2025, the Company entered into a $35.0 million prepaid forward power sales contract, as noted in “Note 7 – Revenue” of which $19.0 million of the proceeds were deposited into a money market account with the administrative agent. The compensating balance is classified as “restricted cash” on the condensed consolidated balance sheets at September 30, 2025. As part of the Third Amendment, the required October 2025 principal payment of $6.0 million and the January 2026 principal payment of $6.5 million, pursuant to the Term Loan, are both now due in January 2026. The balance of the Term Loan will be fully repaid no later than March 2026. All payments will be funded by withdrawals from our compensating balance held in our money market account. Furthermore, the Third Amendment defines certain administrative changes which include, among other things modifications to the required timelines related to reporting and the removal of third-party financial advisors.
On a net basis, bank debt did not change during the nine months ended September 30, 2025. Bank debt totaled $44.0 million as of September 30, 2025 and is comprised of our Term Loan ($19.0 million as of September 30, 2025) and a $75.0 million revolver ($25.0 million borrowed as of September 30, 2025) under the Credit Agreement. Our debt is recorded at amortized cost, which approximates fair value due to the variable interest rates in the agreement and is collateralized primarily by our assets.
Liquidity
As of September 30, 2025, we had additional borrowing capacity of $33.8 million under the revolver and total liquidity of $46.4 million. Our additional borrowing capacity is net of $16.2 million in outstanding letters of credit as of September 30, 2025 that were required to maintain surety bonds and other credit support obligations. Liquidity consists of our additional borrowing capacity and unrestricted cash and cash equivalents.
The Company is currently in discussions with members of its existing bank group and other lenders to refinance our current Credit Agreement. The revolving credit facility matures August 2, 2026 and our Term Loan matures March 31, 2026. The balance of the Term Loan is scheduled to be repaid in January 2026 and March 2026, utilizing restricted cash as set forth in the Third Amendment. As such, our revolving credit facility and Term Loan are listed as current on the September 30, 2025 condensed consolidated balance sheets. While no definitive agreement has been reached as of the reporting date, management believes it is probable that the Credit Agreement will be refinanced on market terms and conditions for similarly situated borrowers and consistent with the existing Credit Agreement. However, there can be no assurance that such efforts will be successful or completed on favorable terms. Failure to refinance our Credit Agreement debt prior to maturity could adversely affect the Company’s liquidity and financial condition.
Fees
Unamortized bank fees and other costs incurred in connection with our initial facility totaled $4.3 million. Additional costs incurred with our Debt Agreement amendments totaled $0.9 million, of which $0.3 million related to our Third Amendment. These unamortized bank fees were deferred and are being amortized over the term of the loan. Unamortized bank fees as of September 30, 2025, and December 31, 2024, were $1.3 million and $2.5 million, respectively. Unused borrowing capacity under the facility was $33.8 million as of September 30, 2025. Commitment fees on the unused portion of the facility are 0.50% per annum.
7
Bank debt, less debt issuance costs, is presented below (in thousands):
Current bank debt
44,000
6,000
Less unamortized debt issuance cost
(1,302)
(1,905)
Net current portion
Long-term bank debt
38,000
(606)
Net long-term portion
Total bank debt
Less total unamortized debt issuance cost
(2,511)
Net bank debt
41,489
Future Maturities (in thousands):
2026
Covenants
The Third Amendment, among other things, deferred the Maximum Leverage Ratio and Minimum Debt Service Coverage Ratios until September 2025. The Maximum Leverage Ratio requirement was changed to 3.00 to 1.00 for our fiscal quarter ending September 30, 2025, and is 2.25 to 1.00 thereafter. The Debt Service Coverage Ratio requirement was changed to 3.25 to 1.00 as long as the Company maintains the required compensating balance, if not, remains at 1.25 to 1.00. The Third Amendment removed the First Lien Leverage Ratio (as defined in the First Amendment to the Credit Agreement) while maintaining the minimum liquidity requirement of $10.0 million.
As of September 30, 2025, we were in compliance with all covenants defined in the Credit Agreement.
Interest Rate
The interest rate on the facility ranges from secured overnight financing rate (“SOFR”) plus 4.00% to SOFR plus 5.00%, depending on our Leverage Ratio. As of September 30, 2025, we were paying SOFR plus 5.00% on the outstanding bank debt which equates to an all-in rate of 9.27%.
ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
Accounts payable and accrued liabilities consist of the following for the indicated dates (in thousands):
Accounts payable
23,272
24,291
Accrued property taxes
4,337
4,185
Accrued payroll
3,258
Workers' compensation reserve
5,408
4,321
Group health insurance
1,500
1,700
Asset retirement obligation - current portion
1,397
1,952
3,441
4,591
Total accounts payable and accrued liabilities
8
(7)
REVENUE
Revenue from Contracts with Customers
We account for a contract with a customer when the parties have executed the contract and are committed to performing their respective obligations, the rights of each party are identified, payment terms are identified, the contract has commercial substance, and it is probable substantially all the consideration will be collected. We recognize revenue when we satisfy a performance obligation by transferring control of a good or service to a customer.
Electric operations
We concluded that for a Power Purchase Agreement (“PPA”) that is not determined to be a lease or derivative, the definition of a contract and the criteria in ASC 606, Revenue from Contracts with Customers (“ASC 606”), is met at the time a PPA is executed by the parties, as this is the point at which enforceable rights and obligations are established. Accordingly, we concluded that a PPA that is not determined to be a lease or derivative constitutes a valid contract under ASC 606.
We recognize revenue daily, based on an output method of capacity made available as part of any stand-ready obligations for contract capacity performance obligations and daily, based on an output method of MWh of electricity delivered.
For the delivered energy performance obligation in the PPA with Hoosier, we recognize revenue daily for actual delivered electricity plus the amortization of the contract liability as a result of the Asset Purchase Agreement with Hoosier. For delivered energy to all other customers, we recognize revenue daily for the actual delivered electricity.
When energy hours at the Merom Hub are priced below our production cost or during outages at Merom, we have the option to make net hourly purchases of power in the MISO market. We record these as “cost of purchased power” on our condensed consolidated statements of operations.
Coal operations
Our coal revenue is derived from sales to customers of coal produced at our facilities. Our customers typically purchase coal directly from our mine sites where the sale occurs and where title, risk of loss, and control pass to the customer at that point. Our customers arrange for and bear the costs of transporting their coal from our mines to their plants or other specified discharge points. Our customers are typically domestic utility companies. Our coal sales agreements with our customers are fixed-priced, fixed-volume supply contracts, or include a pre-determined escalation in price for each year. Price re-opener and index provisions may allow either party to commence a renegotiation of the contract price at a pre-determined time. Price re-opener provisions may automatically set a new price based on the prevailing market price or, in some instances, require us to negotiate a new price, sometimes within specified ranges of prices. The terms of our coal sales agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary by customer.
Coal sales agreements will typically contain coal quality specifications. With coal quality specifications in place, the raw coal sold by us to the customer at the delivery point must be substantially free of magnetic material and other foreign material impurities and crushed to a maximum size as set forth in the respective coal sales agreement. Price adjustments are made and billed in the month the coal sale was recognized based on quality standards that are specified in the coal sales agreement, such as Btu factor, moisture, ash, and sulfur content, and can result in either increases or decreases in the value of the coal shipped.
Disaggregation of Revenue
Revenue is disaggregated by revenue source for our Electric Operations and by primary geographic markets for our Coal Operations, as we believe this best depicts how the nature, amount, timing, and uncertainty of our revenue and cash flows are affected by economic factors.
9
Electric Operations
Delivered energy (including contract liability amortization)
77,776
56,256
194,044
148,490
Capacity
15,459
15,860
45,110
44,506
Total Electric Operations sales
Coal Operations
Outside third-party Indiana customers
27,355
13,338
68,960
46,490
Customers in Florida, North Carolina, Alabama and Georgia
23,901
18,324
50,628
67,603
Total Coal Operations sales
Performance Obligations
We concluded that each megawatt hour (“MWh”) of delivered energy is capable of being distinct as a customer could benefit from each on its own by using/consuming it as a part of its operations. We also concluded that the stand-ready obligation to be available to provide electricity is capable of being distinct as each unit of capacity provides an economic benefit to the holder and could be sold by the customer.
During the second quarter of 2025, we entered into a 17-month, $35.0 million prepaid physically delivered power contract with energy to be delivered at various periods starting in July 2025 through November 2026. During the third quarter of 2025, we entered into a 5-month, $20.0 million prepaid physically delivered power contract with energy to be delivered January 2027 through May 2027. As the total amounts paid upfront by the customers differ from the stand-alone selling price of the transferred power, the Company concluded the contracts contain a significant financing component. The contract liabilities associated with the prepayments will be accreted over the agreement term based upon the Company’s incremental borrowing rates at the time of the contract which approximates 9.50% and 9.92% for the respective contracts, and the accretion is separately recognized as interest expense.
A performance obligation is a promise in a contract with a customer to provide distinct goods or services. Performance obligations are the unit of account for purposes of applying the revenue recognition standard and therefore determine when and how revenue is recognized. In most of our coal contracts, the customer contracts with us to provide coal that meets certain quality criteria. We consider each ton of coal a separate performance obligation and allocate the transaction price based on the base price per the contract, increased or decreased for quality adjustments.
The following table illustrates the balance of all current Electric and Coal Operations contracts allocated to performance obligations that are unsatisfied or partially unsatisfied as of September 30, 2025 and disaggregated by segment and contract duration.
2027
2028
2029
Delivered energy revenues
43,780
172,360
117,300
57,700
13,860
405,000
Capacity revenues
12,980
61,540
51,400
37,330
3,470
166,720
Coal Operations revenues (1)
27,070
151,560
141,850
29,500
349,980
Total revenue
83,830
385,460
310,550
124,530
17,330
921,700
(1) Coal revenues consist of consolidated revenues excluding our intercompany revenues from Merom.
10
Contract Balances
Under ASC 606, the timing of when a performance obligation is satisfied can affect the presentation of accounts receivable, contract assets and contract liabilities. The main distinction between accounts receivable and contract assets is whether consideration is conditional on something other than the passage of time. A receivable is an entity’s right to consideration that is unconditional.
Under the typical payment terms of our contracts with customers, the customer pays us the contracted price for electricity or capacity. For coal contracts, the customer pays us a base price for the coal, increased or decreased for any quality adjustments. Amounts billed and due are recorded as trade accounts receivable and included in accounts receivable in our condensed consolidated balance sheets. Payments received prior to fulfilling our performance obligations are included in contract liabilities in our condensed consolidated balance sheets.
The following table shows our beginning and ending accounts receivable from contracts with customers balance for the periods presented (in thousands):
Accounts receivable from contracts with customers - beginning balance
19,937
Accounts receivable from contracts with customers - ending balance
11,908
As the Company fulfills its contractual obligations, we recognized those amounts in revenues. The following table reconciles our beginning and ending contract liabilities for the periods presented (in thousands):
Total contract liabilities - beginning balance
146,719
113,741
Cash payments received on future contract obligations
102,480
90,082
Revenue recognized, cash payment received in prior period
Revenue recognized, cash payment received in current period
(24,613)
(32,789)
Total contract liabilities - ending balance
147,606
111,798
(8)
INCOME TAXES
For the nine months ended September 30, 2025 and 2024, we recorded income taxes using an estimated annual effective tax rate based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate. The effective tax rate for the nine months ended September 30, 2025 and 2024, was ~ 0% due to recording of a full valuation allowance and ~24%, respectively. Historically, our actual effective tax rates have differed from the statutory effective rate primarily due to the benefit received from statutory percentage depletion in excess of tax basis. The deduction for statutory percentage depletion does not necessarily change proportionately to changes in income (loss) before income taxes.
On July 4, 2025, H.R.1, commonly referred to as the One Big Beautiful Bill Act (“OBBBA”) was enacted. The OBBBA includes a broad range of tax reform provisions affecting businesses, including extending and modifying certain key Tax Cuts & Jobs Act provisions (both domestic and international), expanding certain Inflation Reduction Act incentives, and accelerating the phase-out of or repealing others. We have analyzed the provisions within the act and determined that the benefits relating to capital expenditures and deductibility of interest under IRC Section 163(j) will provide cash flow benefits to the company in 2025 by accelerating deductions for tax purposes. As the material benefits relate to the timing of deductions, there were no material impact affecting the effective tax rate or the valuation allowance determination in the third quarter of 2025.
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(9)
STOCK COMPENSATION PLANS
Non-vested grants as of December 31, 2024
1,034,486
Awarded
355,258
Vested
(577,101)
Forfeited
(14,500)
Non-vested grants as of September 30, 2025
798,143
For the three and nine months ended September 30, 2025, our stock compensation expense was $0.6 million and $2.1 million, respectively. For the three and nine months ended September 30, 2024, our stock compensation expense was $1.1 million and $3.3 million, respectively.
Non-vested RSU grants will vest as follows:
Vesting Year
RSUs Vesting
156,000
225,714
405,213
11,216
As noted in our Form 8-K filed with the SEC on June 2, 2025, on May 29, 2025, shareholders approved the Second Amended and Restated 2008 Restricted Stock Unit Plan (the “RSU Plan”) which, (i) increased the number of shares available for issuance by 2,000,000 shares, and (ii) extended the term of the RSU Plan until May 29, 2035.
As of September 30, 2025, unrecognized stock compensation expense to be recognized over the rolling 3-year vesting period is $6.4 million, and we had 1,897,154 RSUs available for future issuance. RSUs are not allocated earnings and losses as they are considered non-participating securities. Forfeitures are recognized as they occur.
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SELF-INSURANCE
The Company is self-insured for certain risks, including physical damage and operational liability, related to our non-leased underground mining equipment allocated among four mining units dispersed over seven miles. The Company records a liability for self-insured risks when a loss is both probable and reasonably estimable. The Company had no accrual for self-insurance liabilities as of September 30, 2025 or December 31, 2024.
The Company also self-insures for workers’ compensation claims under a guaranteed cost program. Under this program, the Company is responsible for the first $1.0 million per claim up to an aggregate of $4.0 million annually. The Company has restricted cash of $22.8 million and $4.9 million as of September 30, 2025, and December 31, 2024, respectively, which represents cash held and controlled by third parties and is restricted primarily for future workers’ compensation claim payments and the $19.0 million compensating balance on our Term Loan (as discussed in “Note 5 – Bank Debt” above). The Company had $5.4 million and $4.3 million of workers’ compensation reserve as of September 30, 2025 and December 31, 2024, respectively, in “accounts payable and accrued liabilities” on the condensed consolidated balance sheets.
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FAIR VALUE MEASUREMENTS
We account for certain assets and liabilities at fair value. The hierarchy below lists three levels of fair value based on the extent to which inputs used in measuring fair value are observable in the market. We categorize each of our fair value measurements in one of these three levels based on the lowest level input that is significant to the fair value measurement in its entirety. These levels are:
Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities
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occur in sufficient frequency and volume to provide pricing information on an ongoing basis. We have no Level 1 instruments.
Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. We have no Level 2 instruments.
Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). ARO liabilities use Level 3 non-recurring fair value measures.
Nonrecurring Fair Value Measurements
During the fourth quarter of 2024, the Company completed its review of the coal mining facilities and future mining plans. The impairment analysis was based upon the coal mining operating plans of the Company, market driven pricing and cost trends. As part of that analysis, the Company determined the carrying amount of its coal mining long-lived asset group was not recoverable and recorded a non-cash, long-lived asset impairment charge of $215.1 million in 2024.
The discounted cash flow model was calculated using projected economics for the Coal Operations assets, using the Company’s mining plan and reserve estimates to be mined and sold at prevailing commodity prices, operating expenses, and production cost levels, which are classified as Level 3 inputs.
Credit Risk
The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, and restricted cash.
The Company’s cash and cash equivalent and restricted cash balances on deposit with financial institutions total $35.5 million and $12.2 million as of September 30, 2025 and December 31, 2024, respectively, which exceeded FDIC insured limits. The Company regularly monitors these institutions’ financial condition. The Company utilizes large and reputable banking institutions which it believes mitigates these risks. The Company has not experienced any losses in such accounts.
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EQUITY METHOD INVESTMENTS
We own a 50% interest in Sunrise Energy, LLC, which owns gas reserves and gathering equipment with plans to develop and operate such reserves. Sunrise Energy, LLC, also plans to develop and explore for oil, natural gas, and coal-bed methane gas reserves on or near our underground coal reserves. The carrying value of the investment included in our condensed consolidated balance sheets as of September 30, 2025, and December 31, 2024, was $2.0 million and $2.1 million, respectively.
The Company also owns a 50% interest in Oaktown Gas, LLC. Oaktown Gas, LLC operates an emission abatement project through the destruction of gases extracted from the Oaktown mines to generate carbon credits and other emissions offset credits. The carrying value of the investment included in the condensed consolidated balance sheets as of September 30, 2025, and December 31, 2024, was $0.7 million and $0.5 million, respectively.
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ORGANIZATIONAL RESTRUCTURING
On February 23, 2024, (the “Effective Date”), we committed to a reorganization effort in the Coal Operations Segment (the “Reorganization Plan”) that included a workforce reduction of approximately 110 employees, or approximately 12% of the workforce. The reduction in workforce was communicated to employees on the Effective Date and implemented immediately, subject to certain administrative procedures. The Reorganization Plan was designed to strengthen our financial and operational efficiency and create significant operational savings and higher margins in our Coal Operations segment. This step helped advance our transition from a company primarily focused on coal production to a more resilient and diversified integrated independent power producer (“IPP”). As part of this initiative, we substantially idled production at our higher cost surface mines, Prosperity Mine and Freelandville Mine, with minimal
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ongoing production. We also focused our seven units of underground equipment on four units of our lowest cost production at our Oaktown Mine. In connection with the Reorganization Plan, we incurred aggregate expenses of $1.9 million ($1.1 million in the first quarter of 2024 and $0.8 million in the second quarter of 2024) that were included in “labor” in the condensed consolidated statements of operations. These charges related to compensation, tax, professional, and insurance related expenses are considered one-time charges paid during 2024. The coal mining properties asset group was tested for impairment as result of the organizational restructuring passing the undiscounted recoverability test.
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SEGMENTS OF BUSINESS
Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The CODM, who is the Company’s Chief Executive Officer, reviews and assesses operating performance measures related to our Electric Operations and our Coal Operations segments.
Our Electric Operations segment includes the electric power generation facilities of our Merom power plant, which is a two unit, 1080-megawatt rated coal fired power plant located in Sullivan County, Indiana. Our sales region is in MISO Zone 6, which includes Indiana and a portion of western Kentucky. Revenues from our Electric Operations segment consist primarily of delivered energy and capacity revenues. Fuel costs included in our Electric Operations segment include the cost of coal purchased from our Coal Operations segment, which are based on multi-year contracts which approximate market prices at the time the contracts are entered into.
Our Coal Operations segment includes the Oaktown 1 underground mining complex, as well as other currently idled mining facilities, which produce high-quality bituminous coal from the Illinois Basin. Revenues from our Coal Operations segment consist of sales of coal to various third-parties and to Merom. Coal sales to our Electric Operations are based on multi-year contracts which approximate market prices at the time the contracts are entered into. Intercompany coal sales and amounts above actual costs to produce the coal are eliminated in the consolidated statements of operations.
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 our equity method investments.
The CODM evaluates segment performance based upon EBITDA margin for each business segment. EBITDA margin is calculated for each segment as follows:
EBITDA margin for each segment is a key measure used by our CODM and provides information about our core operating performance, significant expenses and ability to generate cash flow. Additionally, EBITDA margin provides investors with the financial analytical framework upon which our CODM bases financial, operational, compensation and planning decisions and presents a measurement that investors, rating agencies and debt holders have indicated is useful in assessing us and our results of operations. Our CODM reviews variable costs, as defined above, in our Electric Operations segment in order to evaluate the efficiency of that segments operations.
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Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the three months ended September 30, 2025 (in thousands):
Delivered Energy
Coal Sales
68,814
Capacity Revenue
Electric Sales
(44,751)
Other Operating Costs (1)
Total Variable Costs
(44,752)
Other Operating and Maintenance Costs (2)
(9,368)
(574)
Cost of Purchased Power
(2,074)
Other Operating and Maintenance Costs
(35,046)
(1,873)
(2,670)
(7,949)
(19,625)
Power Margin Without General and Administrative
27,219
Coal Margin Without General and Administrative
10,899
General and Administrative
(1,308)
(2,062)
Electric Operations — EBITDA Margin
25,911
Coal Operations — EBITDA Margin
8,837
(1) Other operating costs primarily include costs for lime dust.
(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1).
Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the three months ended September 30, 2024 (in thousands):
48,320
(30,181)
(36)
(30,217)
(5,561)
(572)
(3,149)
(27,031)
(492)
(3,094)
(7,360)
(19,361)
25,337
(1,738)
(1,252)
(2,082)
24,085
(3,820)
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Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the nine months ended September 30, 2025 (in thousands):
169,117
(104,150)
(104,160)
(24,602)
(1,564)
(11,086)
(77,147)
(3,932)
(9,270)
(23,731)
(57,671)
71,643
23,465
(3,972)
(6,290)
67,671
17,175
Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the nine months ended September 30, 2024 (in thousands):
160,066
(79,532)
(22)
(79,554)
(22,926)
(2,557)
(7,694)
(80,419)
(1,451)
(10,639)
(22,203)
(66,241)
59,168
210
(3,760)
(8,012)
55,408
(7,802)
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Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the three months ended September 30, 2025 (in thousands):
Corporate and Other
Reconciliation of Revenue:
and Eliminations
Consolidated
Other Revenue
192
1,647
516
Coal Sales (Third-Party)
Coal Sales (Intercompany)
17,558
(17,558)
Operating Revenues
93,427
70,461
(17,042)
Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the three months ended September 30, 2024 (in thousands):
187
721
469
16,658
(16,658)
72,303
49,041
(16,189)
Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the nine months ended September 30, 2025 (in thousands):
3,413
4,370
997
49,529
(49,529)
242,567
173,487
(48,532)
Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the nine months ended September 30, 2024 (in thousands):
518
2,028
1,139
45,973
(45,973)
193,514
162,094
(44,834)
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Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes for the three months ended September 30, 2025 (in thousands):
Reconciliation of Income (Loss)
before Income Taxes:
18,206
44,117
(8,721)
Other Operating Revenue
Depreciation, Depletion and Amortization
(5,131)
(3,992)
(19)
(9,142)
Asset Retirement Obligations Accretion
(126)
(320)
(446)
Exploration Costs
(38)
Gain (loss) on disposal or abandonment of assets, net
2,334
Interest Expense
(2,585)
(2,342)
Equity Method Investment (Loss)
Corporate — General and Administrative
(1,400)
Income (Loss) before Income Taxes
18,261
6,126
(503)
Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes for the three months ended September 30, 2024 (in thousands):
16,998
41,083
(20,478)
(4,802)
(9,013)
(23)
(13,838)
(115)
(295)
(410)
(62)
290
(181)
Loss on Extinguishment of Debt
(3,136)
Corporate — Other Operating and Maintenance Costs
(114)
19,174
(14,690)
(2,698)
Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before
income taxes for the nine months ended September 30, 2025 (in thousands):
48,322
115,993
(32,354)
(15,456)
(14,148)
(57)
(29,661)
(369)
(941)
(1,310)
(157)
2,410
(6,208)
(6,261)
(8,834)
49,051
2,448
(9,388)
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Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes for the nine months ended September 30, 2024 (in thousands):
47,405
102,813
(53,775)
(14,197)
(28,671)
(42,930)
(339)
(869)
(1,208)
(179)
536
(515)
(8,908)
(8,446)
(337)
40,875
(43,865)
(10,745)
Presented below are our Electric and Coal Operations assets and capital expenditures for the periods presented below (in thousands):
Other Reconciliations:
Assets at September 30, 2025
233,865
153,514
22,082
Assets at December 31, 2024
220,477
144,519
4,124
Capital Expenditures at September 30, 2025
25,369
18,908
44,277
Assets at September 30, 2024
217,826
357,913
3,991
579,730
Assets at December 31, 2023
208,331
376,387
5,062
589,780
Capital Expenditures at September 30, 2024
16,121
23,002
483
39,606
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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:
Basic earnings per common share:
Net income (loss) - basic
Weighted average shares outstanding - basic
Basic earnings (loss) per common share
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The following table (in thousands, except per share amounts) sets forth the computation of diluted net income (loss) per share:
Diluted earnings per common share:
Net income (loss) - diluted
Add: Dilutive effects of Restricted Stock Units
427
420
418
Weighted average shares outstanding - diluted
Diluted net income (loss) per share
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CONTINGENCIES
Our Coal Operations subsidiary is party to litigation in which the plaintiffs allege violations of the Fair Labor Standards Act and state law due to alleged failure to compensate for time "donning" and "doffing" equipment and to account for certain bonuses in the calculation of overtime rates and pay. In January 2025, we agreed to settle with the plaintiffs such litigation for $2.8 million, which was recorded in “operating expenses” on our consolidated statements of operations for the year ended December 31, 2024. During the third quarter of 2025, $2.7 million was transferred into an escrow account while the settlement is pending court approval of the settlement terms. At September 30, 2025, $0.1 million related to the settlements remains in “accounts payable and accrued liabilities” on our condensed consolidated balance sheets at September 30, 2025.
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THE FOLLOWING DISCUSSION UPDATES THE MD&A SECTION OF OUR 2024 ANNUAL REPORT ON FORM 10-K AND SHOULD BE READ IN CONJUNCTION THEREWITH.
We are pleased with our favorable results in the third quarter, during which time we generated $146.8 million of revenue with $23.9 million of net income, representing substantial improvement over the $105.2 million of revenue with $1.6 million of net income generated in the prior year period. For the nine months ended September 30, 2025, we generated $367.5 million of revenue with $42.1 million of net income both materially above prior year performance.
Traditional summer weather patterns coupled with higher energy demand and higher natural gas prices provided for a supportive energy-pricing environment during the quarter that led to higher revenue at our Hallador Power subsidiary. Following the completion of Unit 2’s annual maintenance outage in early July 2025, both units operated very well throughout the quarter. We also saw positive results in our Coal Operations resulting from solid coal production, increased shipments and consistent operating costs. The favorable power markets led to increased dispatch levels at both Merom and customer plants, which provided a boost to coal shipments and helped to decrease coal inventories at both the power plant and the mine.
During the third quarter 2025 , the Company entered into a $20.0 million prepaid forward power sales contract with scheduled deliveries throughout the first half of 2027. As we have previously noted, these firm forward sales allow us to improve liquidity from lower future price environments and also provides an advantage, as we saw in this instance, when pricing is stronger. These prepaid sales help us to lock in prices in the near term as we continue to focus on securing a long-term power purchase agreement in support of utility, data center and/or other large scale industrial development. The prepaid funds will be used to support company operations and capital expenditures.
We continue to see significant and accelerating interest in our capacity and energy offerings. As the third quarter progressed, we saw increased activity from both data center developers and load serving entities seeking the scarce inventory of large blocks of capacity and energy that we have available in the coming decade. We are in advanced discussions on both fronts and anticipate making positive progress towards a long-term agreement with a data center developer or load serving entity by early 2026. Each of the interested parties brings a unique perspective to the negotiations and each presents differentiated value creation opportunities and challenges to effectively monetize our capacity and energy offerings. We continue to believe that the evolving energy markets, specifically related to data center growth and favorable load serving entity demand, as well as the newly supportive regulatory environment, are providing us with opportunities that were not available when we began the request for proposal process. We also recognize that these opportunities have an undefined lifespan and we continue to work diligently to secure an agreement that will benefit the Company and our shareholders, both now and in the future.
While we still believe that an agreement with a load serving entity is intrinsically more straightforward to negotiate, can be implemented sooner and could result in greater sales volumes of energy and accredited capacity, we are beginning to see improving timelines on the developer side, especially where the developers had the foresight to speculatively acquire required infrastructure, such as step-down transformers, switch gear and other site-specific level electrical equipment. We anticipate favorable pricing in these potential opportunities, but, as we have highlighted before, data center arrangements are inherently more complex and involve multiple parties, which by its nature adds time and alignment challenges to the negotiation process. Notwithstanding those challenges, returning to non-exclusive negotiations reinforced our belief that we will forge a strategic partnership and create significant value for years to come.
Throughout the past several years, we have expressed our strong belief that the prevailing industry trend of retiring dispatchable generators in favor of non-dispatchable resources, such as wind and solar, will create and has created an unbalanced supply and demand equation, resulting in reduced availability and increased price of accredited capacity. It is our position that the enhanced reliability of dispatchable generation, like Merom, versus non-dispatchable generators will increase the value of the attributes of Hallador Power in the overall energy markets. With this in mind, we continue to evaluate the potential to enhance value through strategic growth initiatives such as the acquisition of retiring or retired generation assets and infrastructure. We are regularly evaluating potential acquisition opportunities to diversify and
increase our dispatchable generation as well as other strategic opportunities, which we believe would inherently diversify our generation portfolio, and provide an avenue to realize future growth opportunities. We believe that this approach has the potential to enhance our financial flexibility and strengthen our position in the evolving energy market.
We remain optimistic about the potential to add to our strategic generation portfolio and the long-term benefits that such a transaction could produce for the company, its shareholders and its customers. This model for growth enables us to capture value by providing accredited capacity and reliable energy. In connection with this belief, on November 3, 2025, Hallador Power submitted an application to MISO’s Expedited Resource Addition Study (ERAS) program to add an additional 525 MW of gas generation at the Merom site. Given the strong market signals that we are currently seeing for our product offerings and the robust interest in the types of long-term arrangements that we are currently evaluating, we believe that it is an appropriate time to explore increasing generation at Merom. While the application is only a first step in our growth process and does not guarantee that we will be able to add the full load which we applied for, or any additional generation as part of ERAS, we are excited to participate in the opportunity and for what it could mean to the future of Hallador. We are currently targeting the generation to come online late in 2028. The process is capital intensive and includes operational, financial, regulatory and legal risks that could impact the project’s viability and/or timeline.
Additionally, we see the potential of enhancing Merom’s reliability, resiliency and flexibility by incorporating natural gas and creating a dual fuel configuration should operational and financial conditions support it. While we remain in the evaluation process, by adding the capability to co-fire with gas or coal, we believe that it could provide Hallador Power and its customers the ability to take advantage of economic fluctuations in fuel cost and provide potential flexibility as we manage other operating expenses. We believe that the ability to co-fire with natural gas and coal will also provide increased resiliency in times where gas availability is limited and allow us to retain the economic advantages of operating our Sunrise Coal subsidiary and leveraging our own fuel supply to ensure competitively priced offerings from third party fuel providers. This evaluation is complex on a variety of levels, specifically customer preference and an evolving regulatory environment, each of which could materially impact the timing and economic benefits of undertaking such a change.
In 2024, we delivered 2.9 million MWh of energy during the first nine months at an average sales price of $50.97 per MWh. In 2025, we delivered 4.0 million MWh of energy during the first nine months at an average sales price of $48.88. As illustrated in the forward sales position table, below, following 2026, we are optimistic that we will be able to sell energy at higher prices in support of data center development and/or to traditional wholesale customers in line with the indicators of a strong forward energy pricing curve.
Shifting to our Coal Operations, during the quarter, we saw improvements in operational expenses and increased shipments. The improved dispatch levels at Merom and our customers’ plants helped to reduce our previously elevated inventories, while still allowing us adequate fuel inventory to position us well to meet industry needs if power plants, including Merom, dispatch at higher levels over the course of the upcoming Winter season.
With renewed support of coal mining and coal fired generation on both the federal and state level, we believe that we are well-positioned to take advantage of opportunities for strategic growth and/or organic expansion. We believe that current market dynamics remain stronger than they were in the past year, and we are actively assessing the timing and feasibility of expanding coal production in 2026. As we have previously said, our average contracted sales price in 2026 across all coal sales contracts is approximately $4.00 per ton higher than the average contracted sales price in 2025.
We currently expect to produce approximately 3.8 million tons of coal in 2025. In the first three quarters of 2025, we produced 3.1 million tons of coal at our Oaktown Mining Complex. We also use supplemental coal from third party suppliers at Merom, typically purchased at favorable prices to help diversify self-production supply risk and to provide us with additional flexibility in our ability to rapidly respond to customer demand if spot market pricing justifies doing so. This optionality to obtain low-cost fuel either internally or from third-parties while capturing upward swings in the commodity markets for coal should allow us to further maximize margins while optimizing fuel costs at Merom.
The continued transformation of Hallador from a commodity focused producer of coal to a vertically integrated IPP remains our primary focus. This allows us to leverage the ongoing impacts of the energy transition to capture the
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expanding margins of the energy markets and capitalize on the rising demand for reliable electricity. As described above, we continue to see very strong interest from data center developers and load serving entities with respect to our energy and accredited capacity offerings. This interest and the number of inquiries accelerated throughout the quarter and we are encouraged by the variety of interested parties and the varied deal structures that we are seeing with respect to our offerings. We continue to believe that our business is well positioned to take advantage of opportunities for growth and cash flow generation as they arise.
Like our competitors, Hallador’s business is affected by various macroeconomic factors, including tariffs and inflationary trends. The U.S. has implemented, or is considering implementing, higher tariffs on imports into the U.S. While such tariffs could potentially result in reduced economic activity, increased costs in operating our business including potential supply chain disruptions, and changes in purchasing behaviors for thermal coal or other potentially adverse economic outcomes, tariffs (or retaliatory trade measures imposed by other countries on U.S. goods) have not yet had a significant impact on our business or results of operations.
Our goal is for Hallador Power to generate up to 6.0 million MWh annually (see Hallador Power’s capacity and utilization information below), if the markets and energy pricing support that level of generation. During the first nine months of the year, Hallador Power generated approximately 3.7 million MWh, or roughly 82.0% of our year-to-date target and economically purchased 0.3 million MWh.
Power Capacity and Utilization
Nameplate capacity (MW)(i)
1,080
Accredited capacity for the period (MW)(ii)
748
828
821
858
Accredited capacity utilization(iii)
93
%
59
69
(i).
Nameplate capacity for the Merom Power Plant refers to the maximum electric output generated by the plant in the period presented and may not reflect actual production. Actual production each period varies based on weather conditions, operational conditions, and other factors.
(ii).
Accredited capacity is based on MISO’s average seasonal accreditations for the year. Average seasonal accreditations were 775 MW and 829 MW per day for 2025 and 2024, respectively. Accreditations are weighted and adjusted annually based on 3-year rolling performance metrics.
(iii).
Accredited capacity utilization is measured as power produced (MWh) divided by accredited capacity for the period (MW) multiplied by 24, times the number of days for the period.
When forward selling Capacity, we target annual sales of around $65.0 million to offset our fixed annual costs at the plant of approximately $60.0 million. For 2025, we have contracted approximately $58.1 million or 89.4% of our target. We believe our forward Capacity sales goals are attainable as illustrated in our “Forward Sales Position” table below.
Our condensed consolidated financial statements should be read in conjunction with this discussion. This analysis includes a discussion of metrics on a per mega-watt hour (MWh) and a per ton basis as derived from the condensed consolidated financial statements, which are considered non-GAAP measurements. These metrics are significant factors in assessing our operating results and profitability.
OVERVIEW
The following is an overview our Electric Operations and Coal Operations results for Q3 2025 compared to Q2 2025.
I.
Q3 2025 Net Income of $23.9 million.
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Key drivers in Q3 2025 Electric Operations results were:
Key drivers in Q3 2025 Coal Operations results were:
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II.
Forward Sales Position (unaudited)*
Q4 2025
Power
Energy
Contracted MWh (in millions)
1.15
4.00
2.31
1.09
0.27
8.82
Average contracted price per MWh
38.07
43.09
50.78
52.94
51.33
Contracted revenue (in millions)
43.78
172.36
117.30
57.70
13.86
405.00
Average daily contracted capacity MW
668
733
623
454
100
Average contracted capacity price per MWd
211
230
226
225
Contracted capacity revenue (in millions)
12.98
61.54
51.40
37.33
3.47
166.72
Total Energy & Capacity Revenue
Contracted Power revenue (in millions)
56.76
233.90
168.70
95.03
17.33
571.72
Coal
Priced tons - 3rd party (in millions)
0.51
2.72
2.50
0.50
6.23
Avg price per ton - 3rd party
53.08
55.72
56.74
59.00
Contracted coal revenue - 3rd party (in millions)
27.07
151.56
141.85
29.50
349.98
TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED
83.83
385.46
310.55
124.53
921.70
Priced tons - Intercompany (in millions)
1.33
2.30
8.23
Avg price per ton - Intercompany
51.00
Contracted coal revenue - Intercompany (in millions)
67.83
419.73
TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT
151.66
502.76
427.85
241.83
1,341.43
* Actual revenue related to 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.
25
LIQUIDITY AND CAPITAL RESOURCES
Liquidity and Capital Resources
Material Off-Balance Sheet Arrangements
CAPITAL EXPENDITURES (“Capex”)
For the nine months ended September 30, 2025, capex was $44.3 million allocated as follows (in millions):
Oaktown – maintenance capex
11.5
Oaktown – investment
7.4
Merom Plant
25.4
Capex per the Condensed Consolidated Statements of Cash Flows
44.3
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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EBITDA Margin
Interest expense
Income before Income Taxes
(1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.
(per MWh)
MWh Generated (in thousands)
1,530
1,074
3,706
2,670
MWh Purchased (in thousands)
48
109
264
243
MWh Sold (in thousands)
1,578
1,183
3,970
2,913
49.29
47.55
48.88
50.97
9.80
13.41
11.36
15.28
59.09
60.96
60.24
66.25
(28.36)
(25.51)
(26.23)
(27.30)
(0.03)
(0.01)
(5.94)
(4.70)
(6.20)
(7.87)
(1.31)
(2.66)
(2.79)
(2.64)
(1.19)
(0.42)
(0.99)
(0.50)
(5.04)
(6.22)
(5.98)
(7.62)
(0.83)
(1.06)
(1.00)
(1.29)
16.42
20.36
17.05
19.02
0.12
0.16
0.86
0.18
(3.25)
(4.06)
(3.89)
(4.87)
(0.08)
(0.10)
(0.09)
(0.12)
(1.64)
(0.15)
(1.56)
(0.18)
11.57
16.21
12.37
14.03
27
Q3 2025 vs. Q3 2024
Key drivers in Electric Operations Q3 results were:
YTD 2025 vs. YTD 2024
28
Key drivers in Electric Operations YTD results were:
29
(per ton)
Tons Sold
1,355
926
3,316
2,989
50.79
52.18
53.55
(0.62)
(0.47)
(0.86)
(25.86)
(29.19)
(23.27)
(26.90)
(1.97)
(3.34)
(2.80)
(3.56)
(14.48)
(20.91)
(17.39)
(22.16)
(1.52)
(2.25)
(1.90)
(2.68)
6.54
(4.13)
5.17
(2.61)
1.22
0.78
1.32
0.68
(2.95)
(9.73)
(4.27)
(9.59)
(0.24)
(0.32)
(0.28)
(0.29)
(0.07)
(0.05)
(0.06)
1.72
0.31
0.73
(1.73)
(2.71)
(1.89)
(2.98)
4.53
(15.87)
(14.67)
30
Key drivers in YTD 2025 Coal Operations results were:
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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
4th 2024
1st 2025
2nd 2025
3rd 2025
T4Qs
Tons produced
971
1,020
1,059
1,034
4,084
Tons sold
875
1,071
890
4,191
Wash plant recovery in %
66
Capex (Coal Operations)
11,079
6,244
5,793
6,873
29,989
Maintenance capex (Coal Operations)
4,492
4,000
3,691
3,846
16,029
Maintenance capex per ton sold (Coal Operations)
5.13
3.73
4.15
2.84
3.82
Average cost per ton sold⁽ⁱ⁾
43.25
43.65
46.03
42.74
4th 2023
1st 2024
2nd 2024
3rd 2024
1,331
1,271
889
873
4,364
1,461
1,214
849
4,450
60
17,867
8,632
7,560
6,810
40,869
13,567
8,085
6,014
4,208
31,874
Maintenance capex per ton (Coal Operations)
9.29
6.66
7.08
4.54
7.16
53.78
51.65
49.94
52.22
(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.
Presentation of Consolidated Information
EARNINGS (LOSS) PER SHARE
(5.06)
0.23
0.19
(0.31)
Our effective tax rate (ETR) is estimated at ~0% and ~24% for the nine months ended September 30, 2025 and 2024, respectively. For the nine months ended September 30, 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.
32
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.
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 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 September 30, 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
33
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.
No material changes from the disclosure in our 2024 Annual Report on Form 10-K.
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 September 30, 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:
35
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.
Except as set forth below, there have been no material changes to the Risk Factors disclosed in Part I, Item 1A, Risk Factors, of the Company's 2024 Form 10-K.
Our Electric and Coal Operations are subject to extensive and costly laws and regulations, and such current and future laws and regulations could increase current operating costs or limit our ability to produce coal.
In October 2025, the Company submitted an application for a National Pollutant Discharge Elimination System (“NPDES”) permit under the proposed U.S. Environmental Protection Agency’s ("EPA") Steam Electric Power Generating Effluent Guidelines ("ELG") Deadline Extensions Rule, published October 2, 2025. The proposed rule extends multiple compliance deadlines originally established by the 2024 ELG rule including deadlines for zero-discharge systems (e.g., flue gas desulfurization wastewater, bottom ash transport water, and combustion residual leachate) by five to six years (e.g., from December 31, 2029 to December 31, 2034) and includes new provisions for alternative applicability dates, transferability between compliance options and authorize alternative applicability dates based on site-specific considerations.
The Company’s permit application was approved November 7, 2025 and is consistent with the extended deadlines and flexibility provided by the proposed Deadline Extensions Rule. The rule is currently in the public comment stage, with comments due November 3, 2025, and has not yet been finalized.
If the finalized ruling does not include the extension of the compliance deadlines the Company would be unable to discharge under the current ELG rule and thus would be out of compliance with the Clean Water Act as of December 31, 2025, potentially subjecting it to enforcement actions, penalties, or required to implement alternative discharge controls immediately.
See Exhibit 95.1 to this Form 10-Q for a listing of our mine safety violations.
Exhibit No.
Document
31.1
SOX 302 Certification - Chief Executive Officer
31.2
SOX 302 Certification - Chief Financial Officer
SOX 906 Certification
95.1
Mine Safety Disclosures
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)
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.
Date: November 10, 2025
/s/ TODD E. TELESZ
Todd E. Telesz, CFO (Principal Financial Officer and Principal Accounting Officer)