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 March 31, 2026
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 May 4, 2026, we had 47,130,392 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
19
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
30
ITEM 4. CONTROLS AND PROCEDURES
32
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
ITEM 1A. RISK FACTORS
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
ITEM 4. MINE SAFETY DISCLOSURES
ITEM 5. OTHER INFORMATION
33
ITEM 6. EXHIBITS
SIGNATURES
34
ITEM 1. FINANCIAL STATEMENTS
Hallador Energy Company
(in thousands, except per share data)
(unaudited)
March 31,
December 31,
2026
2025
ASSETS
Current assets:
Cash and cash equivalents
$
36,778
10,070
Restricted cash
6,585
5,302
Accounts receivable
9,152
13,989
Inventory
47,164
42,534
Parts and supplies
47,893
45,854
Prepaid expenses
1,604
5,638
Other current assets
1,927
—
Total current assets
151,103
123,387
Property, plant and equipment:
Land and mineral rights
69,952
Buildings and equipment
440,682
421,037
Mine development
102,302
Construction work in progress
35,788
39,671
Finance lease right-of-use assets
12,591
Total property, plant and equipment
661,315
645,553
Less - accumulated depreciation, depletion and amortization
(376,481)
(367,775)
Total property, plant and equipment, net
284,834
277,778
Equity method investments
2,528
2,647
Operating lease right-of-use assets
2,315
Other noncurrent assets
7,852
4,241
Total assets
448,632
408,053
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable
19,818
12,594
Accrued liabilities and other
35,078
29,254
Current portion of lease financing
4,981
7,411
Contract liabilities - current
130,170
103,343
Total current liabilities
190,047
152,602
Long-term liabilities:
Bank debt, net
29,678
Long-term lease financing
617
1,338
Deferred income taxes
1,329
1,833
Asset retirement obligations
15,649
15,241
Contract liabilities - long-term
32,148
45,714
Other
3,268
1,814
Total long-term liabilities
53,011
95,618
Total liabilities
243,058
248,220
Commitments and contingencies (Note 14)
Stockholders' equity:
Preferred stock, $.10 par value, 10,000 shares authorized; none issued
Common stock, $.01 par value, 100,000 shares authorized; 47,132 and 43,817 issued and outstanding, as of March 31, 2026 and December 31, 2025, respectively
471
438
Additional paid-in capital
257,992
202,963
Retained deficit
(52,889)
(43,568)
Total stockholders’ equity
205,574
159,833
Total liabilities and stockholders’ equity
See accompanying notes to the condensed consolidated financial statements.
Three Months Ended March 31,
SALES AND OPERATING REVENUES:
Electric sales
65,096
85,943
Coal sales
35,080
30,185
Other revenues
1,631
1,596
Total sales and operating revenues
101,807
117,724
EXPENSES:
Fuel
14,963
15,210
Other operating and maintenance costs
29,156
28,389
Cost of purchased power
14,863
6,840
Utilities
3,333
4,152
Labor
27,388
27,029
Depreciation, depletion and amortization
10,606
14,977
Asset retirement obligations accretion
408
427
Exploration costs
84
21
General and administrative
6,858
6,825
Gain on disposal or abandonment of assets, net
(201)
(21)
Total operating expenses
107,458
103,849
INCOME (LOSS) FROM OPERATIONS
(5,651)
13,875
Interest income
147
63
Interest expense (1)
(3,970)
(3,723)
Loss on extinguishment of debt
(230)
Equity method investment (loss)
(121)
(236)
NET INCOME (LOSS) BEFORE INCOME TAXES
(9,825)
9,979
INCOME TAX EXPENSE (BENEFIT):
Current
Deferred
(504)
Total income tax expense (benefit)
NET INCOME (LOSS)
(9,321)
NET INCOME (LOSS) PER SHARE:
Basic
(0.20)
0.23
Diluted
WEIGHTED AVERAGE SHARES OUTSTANDING
46,519
42,619
43,462
(1) Interest Expense:
Interest on bank debt
862
1,494
Other interest
2,834
1,732
Amortization of debt issuance costs
274
497
Total interest expense
3,970
3,723
(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
121
236
230
Cash paid on asset retirement obligation reclamation
(148)
(156)
Stock-based compensation
1,135
1,084
Amortization of contract liabilities
(36,447)
(35,669)
Accretion on contract liabilities
1,560
Amortization of right-of-use assets
87
1,533
3,224
Change in current assets and liabilities:
4,837
2,856
(4,630)
367
(2,039)
(1,033)
(2,580)
(330)
Accounts payable and accrued liabilities
7,427
3,124
Contract liabilities
46,874
37,297
Net cash provided by operating activities
20,496
38,419
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures
(7,681)
(11,693)
Proceeds from sale of equipment
201
Net cash used in investing activities
(7,480)
(11,672)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on bank debt
(56,700)
(33,000)
Borrowings of bank debt
26,700
12,000
Payments on lease financing
(3,172)
(1,693)
Debt issuance costs
(5,780)
Proceeds from ATM offering, net of issuance costs
Proceeds from public offering, net of issuance costs
53,764
Taxes paid on vesting of RSUs
(38)
Net cash (used in) provided by financing activities
14,975
(22,693)
Increase in cash, cash equivalents, and restricted cash
27,991
4,054
Cash, cash equivalents, and restricted cash, beginning of period
15,372
12,153
Cash, cash equivalents, and restricted cash, end of period
43,363
16,207
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH:
6,891
9,316
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest
1,002
1,830
Non-cash change in capital expenditures included in accounts payable and prepaid expense
9,981
(1,649)
Right-of-use asset additions
2,402
Additional
Total
Common Stock Issued
Paid-in
Retained
Stockholders’
Shares
Amount
Capital
Deficit
Equity
Balance, December 31, 2025
43,817
Stock issued on vesting of RSUs
191
(40)
(81)
(1)
Stock issued in ATM offering
11
Stock issued in public offering
3,194
53,732
Net loss
Balance, March 31, 2026
47,132
Balance, December 31, 2024
42,621
426
189,298
(85,439)
104,285
513
(5)
Net income
Balance, March 31, 2025
42,978
430
190,378
(75,460)
115,348
BASIS OF PRESENTATION
Hallador Energy Company (“Hallador” or the “Company”) is a vertically-integrated, independent power producer (“IPP”) and fuel company with operations primarily in Indiana. The Company operates across multiple stages of the energy supply chain, from accredited capacity and electricity to coal. The Company’s condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). The condensed consolidated financial statements include the accounts of Hallador and our wholly owned subsidiaries, including our main operating subsidiaries, Hallador Power Company, LLC (“Hallador Power”) and Sunrise Coal, LLC (“Sunrise”) and their respective subsidiaries, as well as Hourglass Sands, LLC. Additionally, we hold 50% interests in Sunrise Energy, LLC (“Sunrise Energy”), a private gas exploration company with operations in Indiana and Oaktown Gas, LLC (“Oaktown Gas”), which we account for using the equity method. Our operations include Hallador Power which provides accredited capacity and energy to utilities and other energy market participants through the MISO interconnection, and Sunrise which mines bituminous coal in Indiana to serve various power plants in the Midwest and Southeast United States.
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.
Our unaudited condensed consolidated financial statements have been prepared in accordance with GAAP and with the instructions to Form 10-Q and Article 10 of Regulation S-X for interim financial information. Accordingly, these financial statements do not include all of the information required by GAAP or Securities and Exchange Commission (“SEC”) rules and regulations for complete financial statements. In the opinion of management, these financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results of operations for the interim periods presented. The results of operations for any interim period are not necessarily indicative of results for the full year. These unaudited condensed consolidated financial statements should be read in conjunction with our 2025 consolidated financial statements and notes thereto included in our 2025 Annual Report on Form 10-K (our “2025 10-K”).
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Estimates and assumptions are used in accounting for, among other things, deferred income tax accounts, coal reserves, depreciation, depletion, and amortization, impairment analyses, and calculation of asset retirement obligations (“ARO”). Actual results could differ from those estimates.
(2)
RECENT ACCOUNTING PRONOUNCEMENTS
Recent Accounting Pronouncements - Adopted
The Company has adopted Accounting Standards Update (“ASU”) 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures ("ASU 2023-09"), which is effective for fiscal years beginning after December 15, 2024. 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. Please see “Note 7 – Income Taxes” for additional information.
Recent Accounting Pronouncements – Not Yet Adopted
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 (“ASU 2024-03”). The update is intended to improve 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)
INVENTORY
Inventory is valued at the lower of cost or net realizable value (“NRV”). Coal inventory includes NRV adjustments of $0.1 million as of March 31, 2026, and December 31, 2025. During 2025, as part of the Company’s routine inventory reconciliation process, a downward adjustment of $2.6 million was recorded to coal inventory.
(4)
BANK DEBT
New Credit Facility
On March 5, 2026, Hallador entered into a credit agreement with Texas Capital Bank, as administrative agent, and Old National Bank, among others, that replaces the Credit Agreement with PNC Bank, National Association and includes a $75.0 million senior secured revolving credit facility (the "New Revolving Credit Facility") and a $45.0 million senior secured term loan facility (the "Delayed Draw Term Loan", and together with the New Revolving Credit Facility, the "New Credit Facility"). The New Revolving Credit Facility includes (i) a $25.0 million sub-facility for letters of credit and (ii) a $10.0 million sub-facility for swingline loans. The Company may, subject to conditions set forth in the New Credit Facility, request additional revolving facility commitments and incremental term loan commitments in an aggregate amount not to exceed $25.0 million. The Company and certain of its subsidiaries, as guarantors under the New Credit Facility, granted a security interest in substantially all of their assets to secure the Company’s obligations under the New Credit Facility.
The New Credit Facility bears interest at a rate equal to, at the Company’s election, either a base rate or term secured overnight financing rate (“SOFR”), plus an applicable margin based upon the Company’s total leverage ratio. Under the New Credit Facility, (A) base rate loans will bear interest at a rate equal to the greater of (i) the prime rate, (ii) the sum of the Federal Funds Rate plus one half of one percent (0.50%), and (iii) the term SOFR plus one percent (1.00%), in each case, plus the applicable margin for base rate loans, which ranges from 2.25% to 2.75%, and (B) term SOFR loans will bear interest at term SOFR, plus the applicable margin for term SOFR loans, which ranges from 3.25% to 3.75%. The New Credit Facility includes a commitment fee of 0.50% on the daily unused portions of the New Revolving Credit Facility.
If the Delayed Draw Term Loan occurs, which is subject to meeting certain conditions, the principal balance of the Delayed Draw Term Loan shall be due and payable in equal quarterly installments of 2.5% of the original principal amount of such Delayed Draw Term Loan with a final payment of the remaining balance upon maturity. The New Credit Facility matures on March 5, 2029, and is collateralized by substantially all our assets. When drawn, the proceeds from the New Credit Facility may be used for ongoing working capital and general corporate purposes.
The Company used borrowings from the New Credit Facility, together with cash on hand to repay the Prior Credit Agreement (as defined below) in full. As of March 31, 2026, there were no outstanding borrowings under the New Revolving Credit Facility with $14.2 million in outstanding letters of credit. There was no Delayed Draw Term Loan balance outstanding at March 31, 2026.
6
Prior Credit Agreement
The Company was party to a credit agreement with PNC, in its capacity as administrative agent, which consisted of a revolving credit facility of up to $75.0 million and a term loan.
On June 27, 2025, the Company executed the Third Amendment (“Third Amendment”) to our Credit Agreement, 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 and deferring certain covenants until the third quarter of 2025. During the second quarter of 2025, the Company entered into a $35.0 million prepaid forward power sales contract of which $19.0 million of the proceeds were deposited into a money market account with the administrative agent as a compensating balance. The compensating balance was utilized to fully repay the outstanding term loan during the fourth quarter of 2025. As of March 5, 2026, the Company fully repaid its revolving credit facility.
Liquidity
Liquidity consists of our additional borrowing capacity and unrestricted cash and cash equivalents. As of March 31, 2026, we had additional borrowing capacity of $60.8 million under the New Revolving Credit Facility and total liquidity of $97.5 million. Our additional borrowing capacity is net of $14.2 million in outstanding letters of credit as of March 31, 2026 that were required to maintain surety bonds and other credit support obligations.
Fees
Bank fees and other costs incurred in connection with the New Credit Facility totaled $5.8 million and are reflected in other assets on the condensed consolidated balance sheets. These fees will be amortized over the term of the loan. Unamortized bank fees as of March 31, 2026, and December 31, 2025, were $5.6 million and $0.3 million, respectively. The New Credit Facility includes a commitment fee of 0.50% on any daily unused portions of the New Revolving Credit Facility.
Unamortized bank fees and other costs incurred in connection with our Prior Credit Agreement of $0.2 million were recorded as a loss on extinguishment of debt on the condensed consolidated statements of operations.
Bank debt, less debt issuance costs, is presented below (in thousands):
Current bank debt
Less unamortized debt issuance cost (1)
Net current portion
Long-term bank debt
30,000
(322)
Net long-term portion
Total bank debt
Less total unamortized debt issuance cost (1)
Net bank debt
7
Covenants
Prior to the date on which the conditions to availability of the Delayed Draw Term Loan are satisfied, our covenants include:
After the conditions to availability of the Delayed Draw Term Loan are satisfied, our covenants will include:
As of March 31, 2026, we were in compliance with all covenants defined in the New Credit Facility.
Interest Rate
The New Credit Facility bears interest with margins ranging from 2.25% to 3.75% above SOFR or the applicable base rate, subject to a SOFR floor of 1.00%, as further described above. The applicable margin is determined based upon the Company's leverage ratio and the type of loan drawn. As of March 31, 2026, we were subject to paying the applicable SOFR plus 3.50% on any outstanding bank debt which equates to an all-in rate of 7.16%.
ACCRUED LIABILITIES AND OTHER
Accrued liabilities consist of the following for the indicated dates (in thousands):
Accrued liabilities
14,320
10,829
Workers' compensation reserve
4,732
5,223
Accrued property taxes
4,474
3,900
Accrued payroll
5,076
3,037
ARO - current portion
2,460
2,606
Group heath insurance
1,350
1,420
Operating lease liability - current portion
608
2,058
2,239
Total accrued liabilities and other
(6)
REVENUE
Revenue from Contracts with Customers
We account for contracts with customers 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
8
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.
Under accredited capacity PPAs, we recognize revenue daily, based on an output method of capacity made available as part of any stand-ready obligations for contracted accredited capacity performance obligations.
For delivered energy PPAs, we recognize revenue daily for the actual delivered MWh of electricity. For the prepaid delivered energy PPAs, we recognize revenue daily for the funds received for the actual delivered MWh of electricity plus any accretion attributable to the time value of money.
When there is an outage at one of the generating units at Merom or energy hours at the Merom Hub are priced below our production cost, we have the option to make net hourly purchases of power in the MISO market to satisfy our obligations, which we record as cost of purchased power in our condensed consolidated statements of operations.
Coal operations
Our coal revenue is derived from sales to customers of coal produced at our mining facilities. Our customers typically purchase coal free on board from our mine sites where title, risk of loss, and control pass to the customer. 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. Coal sales agreements with our customers are fixed-priced, fixed-volume supply contracts, but some include a pre-determined escalation in price for each year and some allow for our customers to vary the fixed-volume by pre-determined quantities during a set period, such as quarterly. 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 typically contain coal quality specifications which require the raw coal sold by us to the customer to be (i) substantially free of magnetic material and other foreign material impurities and (ii) 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 British thermal unit factor, moisture, ash, and sulfur content, and can result in either increases or decreases in the value of the coal shipped. When applicable, we have constrained the expected value of variable consideration in our estimation of transaction price and only included this consideration to the extent that it is probable that a significant revenue reversal will not occur.
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.
Delivered energy (including contract liability amortization)
49,562
72,136
Accredited capacity
15,534
13,807
Total Electric Operations sales
9
Coal Operations
Third party Indiana customers
25,913
20,314
Other customers
9,167
9,871
Total Coal Operations sales
Performance Obligations
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.
We concluded that each 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 accredited capacity provides an economic benefit to the holder and could be sold by the customer.
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 using 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, 2026 and disaggregated by segment and contract duration (in thousands).
2027
2028
2029
Delivered energy revenue
135,590
142,290
57,700
13,860
349,440
Accredited capacity revenue
52,820
75,260
73,280
20,440
221,800
Coal Operations revenue (1)
117,030
141,850
29,500
288,380
Total revenue
305,440
359,400
160,480
34,300
859,620
(1) Coal Operations revenue consists of consolidated revenue 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 accredited 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. When the Company receives customer payments more than one year in advance of the related performance obligations, in accordance with ASC 606, the Company adjusts the transaction price for the significant financing component associated with these contracts at risk adjusted market rates. The resulting interest accretion is recognized as interest expense over the period between the customer payment date and the expected satisfaction of the performance obligation.
10
The following table shows our beginning and ending accounts receivable balances from contracts with customers for the periods presented (in thousands):
Accounts receivable from contracts with customers - beginning balance
15,438
Accounts receivable from contracts with customers - ending balance
12,582
As the Company fulfills its contractual obligations, we recognized those amounts in revenue. The following table reconciles our beginning and ending contract liabilities for the periods presented (in thousands):
Total contract liabilities - beginning balance
149,057
146,719
Cash payments received on future contract obligations
Revenue recognized, cash payment received in prior period
Total contract liabilities - ending balance
162,318
149,907
(7)
INCOME TAXES
For the three months ended March 31, 2026 and 2025, 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, 2026 and 2025, was approximately 5.2% and 0%, respectively, due to recording of a valuation allowance. Historically, our actual effective tax rates 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 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 period that OBBBA was enacted.
(8)
STOCK COMPENSATION PLANS
Non-vested grants and activity for the period presented are as follows (in whole shares):
Non-vested grants as of December 31, 2025
586,101
Awarded
9,973
Vested
(191,307)
Forfeited
Non-vested grants as of March 31, 2026
404,767
Stock compensation expense was $1.1 million for the three months ended March 31, 2026 and 2025.
Non-vested restricted stock unit (“RSU”) grants will vest as follows (in whole shares):
Vesting Year
RSUs Vesting
15,872
377,679
11,216
As of March 31, 2026, unrecognized stock compensation expense to be recognized over the respective vesting period is $3.2 million, and we had 2,075,261 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.
(9)
SELF-INSURANCE
The Company is self-insured for certain risks, including physical damage and operational liability, related to our non-leased underground mining equipment. 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 March 31, 2026 or December 31, 2025.
The Company also self-insures for a portion of its 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. As of March 31, 2026 and December 31, 2025 the Company has restricted cash of $3.3 million and $3.0 million as of March 31, 2026 and December 31, 2025, respectively, for future workers’ compensation claim payments. The Company had $4.7 million and $5.2 million of workers’ compensation reserve as of March 31, 2026 and December 31, 2025, respectively, in 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 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.
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.
The carrying amounts for cash equivalents, accounts receivable, accounts payable, accrued liabilities and other, approximate fair value due to the short maturity of those instruments. 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.
Credit Risk
The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, and restricted cash.
12
The Company’s cash and cash equivalent and restricted cash balances on deposit with financial institutions total $43.4 million and $15.4 million as of March 31, 2026 and December 31, 2025, 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 which owns gas reserves and gathering equipment with plans to develop and operate such reserves. Sunrise Energy 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 was $1.9 million as of March 31, 2026 and December 31, 2025.
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, 2026 and December 31, 2025, was $0.6 million and $0.7 million, respectively.
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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 accredited 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 were agreed.
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. Revenue from our Coal Operations segment consists of sales of coal to various third parties and to Merom. Coal sales to our Electric Operations are based on multi-year contracts that approximated market prices at the time the contracts were agreed. Intercompany coal sales and amounts above actual costs to produce the coal are eliminated in the condensed 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 Segment EBITDA for each business segment. Segment EBITDA is calculated for each segment as follows:
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Segment EBITDA 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, Segment EBITDA 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 segment’s operations.
Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the three months ended March 31, 2026 (in thousands):
Delivered energy
46,412
(27,527)
Other operating costs (1)
(29)
Total variable costs
(27,556)
Other operating and maintenance costs (2)
(8,854)
(528)
(14,863)
(20,273)
(134)
(3,199)
(8,129)
(19,259)
Power margin without general and administrative
5,560
Coal margin without general and administrative
3,153
(1,310)
(2,211)
Electric Operations — Segment EBITDA
4,250
Coal Operations — Segment EBITDA
942
(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 included in fuel and other operating costs.
Presented below are the Electric and Coal Operations key metrics reviewed by the CODM for the three months ended March 31, 2025 (in thousands):
54,774
(38,071)
(38,079)
(4,527)
(556)
(6,840)
(23,854)
(676)
(3,476)
(8,143)
(18,886)
27,678
8,002
(1,535)
(2,313)
26,143
5,689
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Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the three months ended March 31, 2026 (in thousands):
Corporate and Other
Reconciliation of Revenue:
and Eliminations
Consolidated
Other operating revenue
137
1,140
354
Coal sales (third party)
Coal sales (intercompany)
11,332
(11,332)
Operating Revenue
65,233
47,552
(10,978)
Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues for the three months ended March 31, 2025 (in thousands):
1,261
248
24,589
(24,589)
86,030
56,035
(24,341)
Presented below is our reconciliation of Segment EBITDA to the most comparable GAAP account, income (loss) before income taxes for the three months ended March 31, 2026 (in thousands):
Reconciliation of Income (Loss) before Income Taxes:
Income (Loss) before Income Taxes
(5,038)
(2,979)
(1,808)
(137)
(1,140)
(354)
(1,631)
6,383
4,204
ARO accretion
131
277
(Gain) loss on disposal or abandonment of assets, net
(36)
(111)
(147)
Interest expense
2,947
808
215
Corporate — general and administrative
3,337
Segment EBITDA
1,760
6,952
Presented below is our reconciliation of Segment EBITDA to the most comparable GAAP account, income (loss) before income taxes for the three months ended March 31, 2025 (in thousands):
19,217
(5,082)
(4,156)
(87)
(1,261)
(248)
(1,596)
5,161
9,797
120
307
(63)
1,991
2,977
(1,172)
30,660
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Presented below are our Electric and Coal Operations assets and capital expenditures for the periods presented below (in thousands):
Other Reconciliations:
Coal Operations (1)
Assets at March 31, 2026
254,332
184,915
9,385
Assets at December 31, 2025
256,529
148,957
2,567
Capital Expenditures for the period ending March 31, 2026
3,889
3,792
7,681
Cash and cash equivalents included in Coal Operations assets were $36.3 million and $9.4 million as of March 31, 2026 and December 31, 2025, respectively.
Assets at March 31, 2025
222,865
141,023
2,209
366,097
Assets at December 31, 2024
220,477
144,519
4,124
369,120
Capital Expenditures for the period ending March 31, 2025
5,449
6,244
11,693
Cash and cash equivalents included in Coal Operations assets were $5.6 million and $6.9 million as of March 31, 2025 and December 31, 2024, respectively.
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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 presented:
Basic earnings per common share:
Net income (loss) - basic
Weighted average shares outstanding - basic
Basic earnings (loss) per common share
16
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
843
Weighted average shares outstanding - diluted
Diluted net income (loss) per share
The computation of diluted net loss per share for the three months ended March 31, 2026 excludes 389,276 potentially dilutive securities related to unvested restricted stock units as their inclusion would have been anti-dilutive.
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CONTINGENCIES
Our Coal Operations subsidiary was party to litigation in which the plaintiffs alleged 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, we transferred $2.7 million into an escrow account and in late 2025 the settlement terms were approved by the court. At December 31, 2025, there were no further amounts accrued on our consolidated balance sheet related to this litigation.
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AT MARKET AGREEMENT (“ATM”) AND CONFIDENTIALLY MARKETED PUBLIC OFFERING (“CMPO”)
ATM
On December 18, 2023, we entered into an At Market Issuance Sales Agreement (the “Sales Agreement”) with B. Riley Securities, Inc. (the “Agent”), pursuant to which we may issue and sell, from time to time, shares (the “Shares”) of our common stock, par value $0.01 per share (the “Common Stock”), with aggregate gross proceeds of up to $50.0 million through an “at-the-market” equity offering program under which the Agent will act as sales agent (the “ATM Program”). Under the Sales Agreement, we or the Agent have the right, by giving five days’ notice, to terminate the Sales Agreement in our and the Agent’s sole discretion. On December 16, 2025, the Company increased the aggregate gross sales proceeds under the ATM Program from $50.0 million to $100.0 million by amending the Sales Agreement.
During the three months ended March 31, 2026, we issued 10,832 shares of Common Stock under the ATM Program for net proceeds of $0.2 million. During the year ended December 31, 2025, we issued 697,227 shares of Common Stock under the ATM Program for net proceeds of $13.5 million. In January 2026, the Company delivered written notice to the Agent to terminate the Sales Agreement effective January 18, 2026. As a result of the termination of the Sales Agreement, the Company will not offer or sell any further shares under the ATM Program.
CMPO
In January 2026, the Company conducted a confidentially marketed public offering (the "CMPO") pursuant to a base prospectus and a final prospectus supplement that were filed with the SEC. The Company sold a total of 3,194,444 shares of common stock, at a price to the public of $18.00 per share for aggregate gross proceeds of approximately $57.5 million, including the exercise of the underwriter’s option prior to deducting underwriting discounts, commissions, and other offering expenses of $3.7 million.
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SUBSEQUENT EVENTS
On May 1, 2026, the Company entered into a Master Power Purchase and Sale Agreement Long-Form Confirmation Letter (the "Capacity PPA") with a subsidiary of a utility. The Capacity PPA provides for the sale of approximately two-thirds of the Company’s accredited capacity from its Merom Generating Station, commencing in late 2028 and extending through mid-2040, and is expected to generate cumulative revenue in excess of $1.0 billion. The Capacity PPA is subject to customary regulatory approvals, including approval by the Indiana Utility Regulatory Commission (“IURC”). Completion of the IURC’s review is anticipated in the second half of 2026.
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The following discussion and analysis, which should be read in conjunction with our consolidated financial statements and the discussion and analysis included in our 2025 10-K, is intended to assist in providing an understanding of changes in our results of operations and financial condition and is organized as follows:
The capitalized terms used below have been defined in the notes to our condensed consolidated financial statements. In the following text, the terms “we,” “our,” “the Company” and “us” may refer, as the context requires, to Hallador Energy Company (“Hallador”) or collectively to Hallador and its subsidiaries.
Unless otherwise indicated, operational data is presented as of March 31, 2026.
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:
20
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 2025 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.
OVERVIEW
General
Hallador is a vertically integrated, independent power producer (“IPP”) and fuel company with operations primarily in Indiana. The Company operates across multiple stages of the energy supply chain, from accredited capacity and energy to coal. The Company’s electric operations are located within the MISO footprint. Our operations include Hallador Power which provides accredited capacity and energy to utilities and other energy market participants through its MISO interconnection, and Sunrise which mines bituminous coal in Indiana to serve various power plants in the Midwest and Southeast United States.
Operations
Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The Company also holds 50% interests in Sunrise Energy, LLC (“Sunrise Energy”) and Oaktown Gas, LLC (“Oaktown Gas”), which are accounted for using the equity method. Through its operating subsidiaries, the Company delivers three main products to its customers.
Accredited Capacity. Hallador Power, the Company’s wholly-owned electric subsidiary, owns and operates the Merom Power Plant (“Merom”), a 1,080 MW coal-fired power generating station, consisting of two steam turbine generators. Unit 1 entered commercial operations in 1982 and Unit 2 in 1983. The units are dispatched through its MISO interconnection. In order to purchase energy through the MISO system, an end user must supply or purchase accredited capacity for an equivalent load. As accredited capacity is primarily available in large quantities from dispatchable sources of energy, such as natural gas and coal-fired power plants, Hallador Power sells accredited capacity to utilities and other energy market participants within the MISO system through Power Purchase Agreements (“PPA”) and other bilateral transactions.
Energy. In addition to accredited capacity, Hallador Power sells wholesale energy to utilities, generation and transmission cooperatives, and other energy market participants within the MISO system through PPAs and other bilateral transactions, and sells on a spot basis in the day-ahead and real-time MISO markets.
Coal. Sunrise, the Company’s wholly-owned mining subsidiary, mines coal from reserves found in the Illinois Basin (“ILB”). Coal mined by Sunrise is used as a primary fuel source for generating electricity at various power plants in the Midwest and Southeast United States. In addition, Sunrise has a developed infrastructure for the transport of coal, which is typically sold free on board from the shipping point, including rail networks and truck loading systems, facilitating the efficient movement of the resource from the mine to its customers. Sunrise’s Oaktown Mining Complex is about twenty miles from Merom, which is located in Sullivan County, Indiana, enabling Merom and Sunrise to take advantage of low-cost fuel on a delivered basis.
Strategy and Management Focus
We view our business as two integrated operations, “Electric Operations” (our gigawatt Merom power generating station), and “Coal Operations” (our coal mining and coal sales group).
We strive to achieve margin expansion through organic revenue growth and profitability in our operations by negotiating and fulfilling contracts for accredited capacity, wholesale energy, and thermal coal to utilities and other energy market participants. We continue to monitor opportunities to expand the volume of our electric generation capabilities through expansion of existing facilities utilizing MISO’s ERAS program, or via acquisition. We continue to evaluate other strategic transactions that could add diversification, durability, scale, and geographic expansion opportunities to our Electric Operations. While these opportunities are limited and complex, we believe that Hallador is well-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 industrial customers, with minimal impact to retail consumers. In addition, we focus our organic capital investments on strategic maintenance projects to maintain our safe operational performance and improve the reliability of Merom.
As discussed further under “Material Changes in Financial Condition — Capitalization” below, we also seek to maintain our debt at levels that provide for attractive equity returns without assuming undue risk.
Competition and Other External Factors
We are experiencing competition in both our Electric and Coal Operations. This competition drives lower market prices for our products and services. Competitors for our Electric Operations include other power generators who bid into the MISO system, while competitors for our Coal Operations include other mining entities that are able to service our existing and potential customers via truck or rail within the Midwest and Southeast United States.
22
MATERIAL CHANGES IN RESULTS OF OPERATIONS
Our contracted forward sales for accredited capacity, energy, and coal are detailed below with estimated revenue from forward sales of $1.2 billion as of March 31, 2026.
Forward Sales Position (unaudited)*
Power
Accredited Capacity
Average daily contracted accredited capacity MW
781
782
668
340
Average contracted accredited capacity price per MWd
246
264
300
398
Contracted accredited capacity revenue (in millions)
52.82
75.26
73.28
20.44
221.80
Energy
Contracted MWh (in millions)
3.10
3.06
1.09
0.27
7.52
Average contracted price per MWh
43.74
46.50
52.94
51.33
Contracted revenue (in millions)
135.59
142.29
57.70
13.86
349.44
Total Accredited Capacity & Energy Revenue (in millions)
188.41
217.55
130.98
34.30
571.24
Coal
Priced tons - 3rd party (in millions)
2.10
2.50
0.50
5.10
Avg price per ton - 3rd party
55.73
56.74
59.00
Contracted coal revenue - 3rd party (in millions)
117.03
141.85
29.50
288.38
TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED
305.44
359.40
160.48
859.62
Priced tons - Intercompany (in millions)
2.08
2.30
3.17
7.55
Avg price per ton - Intercompany
51.00
Contracted coal revenue - Intercompany (in millions)
106.08
117.30
161.67
385.05
TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT
411.52
476.70
322.15
1,244.67
* 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, including rollover of unfulfilled coal commitments into future periods, and potential force majeure events. Forward sales figures in the 2026 column are for the period from April 1, 2026 through December 31, 2026.
Discussion and Analysis of our Reportable Segments
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 our 50% interests in Sunrise Energy and Oaktown Gas, which we account for using the equity method.
23
Delivered Energy
Accredited Capacity Revenue
Electric Sales
Other Operating Costs (1)
Other Operating and Maintenance Costs (2)
Cost of Purchased Power
General and Administrative
Other Operating Revenue
Depreciation, Depletion and Amortization
(6,383)
(5,161)
Asset Retirement Obligations Accretion
(131)
(120)
Interest Income
36
Interest Expense
(2,947)
(1,732)
Income before Income Taxes
(per MWh)
MWh Generated (in thousands)
938
1,422
MWh Purchased (in thousands)
183
132
MWh Sold (in thousands)
1,121
1,554
44.21
46.42
8.88
58.07
55.30
(24.56)
(24.50)
(0.03)
(0.01)
(7.90)
(2.91)
(13.26)
(4.40)
(0.12)
(0.44)
(7.25)
(5.24)
(1.17)
(0.99)
3.78
16.81
0.12
0.06
(5.69)
(3.32)
(0.08)
0.03
(2.63)
(1.11)
(4.51)
12.36
24
Segment operating revenues from electric operations decreased $20.8 million, or 24.3%, compared to the first quarter of 2025, attributable to a $22.6 million decrease in sales of delivered energy partially offset by a $1.7 million increase in accredited capacity revenue. Our Electric Operations generated 0.5 million fewer MWh, but purchased an additional 0.1 million MWh for resale resulting in a net decrease of energy sales of 0.4 million MWh, a decrease of 27.9% compared to the first quarter of 2025. Lower plant availability in the first quarter of 2026 due to equipment issues at Merom had a significant impact on the total MWh generated. The impacted generating unit is scheduled to undergo a major maintenance outage beginning in May 2026, which we expect will improve performance upon completion. The price per MWh for delivered energy decreased 4.8% year-over-year from $46.42 for the three-month period ended March 31, 2025 to $44.21 in 2026. Accredited capacity revenue increased 12.5% to $15.5 million for the three-month period ended March 31, 2026 from $13.8 million in the comparable prior year period.
Fuel costs on a segment basis decreased $10.5 million, or 27.7%, from the first quarter of 2025. Fuel costs on a consolidated basis decreased $0.2 million or 1.5%, from the first quarter of 2025. The decrease is due to electricity generation falling by 0.5 million MWh, or 34.0%. We used 0.2 million tons less in production on both a segment and consolidated basis, as we utilized 0.2 million less tons produced at the Oaktown mining complex in 2026 compared to 2025. The decrease in electric power generation was attributable to the aforementioned equipment issues, which resulted in 0.5 million lower MWh generated, compared to the same period in 2025. The weather contributed to higher demand for electricity and natural gas causing an increase in the average spot price at Chicago citygate of $1.30 per thousand cubic feet to $5.70 per thousand cubic feet in January 2026 compared to January 2025. Total fuel costs were impacted by an increase in the cost of coal consumed from $53.80 per ton in 2025 to $54.58 per ton in 2026.
Other operating and maintenance costs increased $4.3 million, or 95.6%, from the first quarter of 2025. The increase was driven by increased maintenance activities attributable to the aforementioned equipment issues at Merom. In addition to the increased maintenance activities in the first quarter of 2026, the impacted generating unit will receive a major maintenance outage beginning in May.
Cost of purchased power increased $8.0 million, or 117.3%, from the first quarter of 2025. When there is an outage at one of the generating units at Merom or energy hours at the Merom Hub are priced below our production cost, we have the option to make economic net hourly purchases of power in the MISO market to satisfy our obligations, which we record as cost of purchased power. In 2026, we purchased an incremental 51,000 MWh compared to 2025, an increase of 38.6% that was further impacted by the energy pricing dynamics at the time of the purchases.
Utilities expense decreased $0.5 million, or 80.2%, in the first quarter of 2026 compared to 2025. The change was attributable to decreased production at Merom, as well as new meters installed in 2025 that allow for active management of pricing of auxiliary power in the day-ahead market.
Labor expenses were largely flat for the first quarter of 2026 versus the comparable period in 2025 as headcount was relatively stable year-over-year.
Interest expense increased $1.2 million, or 70.2%, from the first quarter of 2025. The increase in our interest expense relates to accretion on our prepaid delivered energy contracts that were entered into in 2024 and 2025.
Income before income taxes decreased $24.3 million from $19.2 million of income before taxes in the first quarter of 2025 to a loss before taxes of $5.0 million in the first quarter of 2026, which is attributable to the items described in the discussion above.
25
Coal Sales
Other Operating and Maintenance Costs
(4,204)
(9,797)
ARO Accretion
(277)
(307)
Exploration Costs
(84)
Gain on Disposal or Abandonment of Assets, Net
111
(808)
(1,991)
(per ton)
Tons Sold (in thousands)
854
1,071
54.35
51.14
(0.62)
(0.52)
(23.74)
(22.27)
(3.75)
(3.25)
(22.55)
(17.63)
(2.59)
(2.16)
1.10
5.31
1.33
1.18
(4.92)
(9.15)
(0.32)
(0.29)
(0.10)
(0.02)
0.24
0.02
0.13
(0.95)
(1.86)
(3.49)
(4.75)
Segment operating revenue from coal operations (including intercompany sales to Merom) decreased $8.4 million, or 15.3%, compared to the first quarter of 2025. The decrease was driven by lower volume partially offset by an increase in the average sales price for our coal. We sold 0.9 million tons of coal during the first quarter of 2026, a decrease of 0.2 million tons, or 20.3%, versus 2025. Our average sales price, on a segment basis, increased $3.21 per ton from $51.14 per ton to $54.35 per ton. The decreased sales were driven by lower coal demand from Merom due to the aforementioned equipment issues. Sunrise sold 0.3 million fewer tons of coal to Merom, offset by a 7.2% increase in tons sold to third parties in the first quarter of 2026 compared to 2025. On a consolidated basis, third party sales increased $4.9 million, or 16.2%, versus the first quarter of 2025 attributable to 0.3 million incremental tons sold to third parties, supplemented by an 8.4% increase in our average third party price per ton.
Other operating and maintenance costs decreased $3.6 million, or 15.0%, which is attributable to the decrease in total tons sold of 0.2 million, or 20.3%, versus the first quarter of 2025, partially offset by mine expansion costs at Oaktown. Labor expenses increased $0.4 million, or 2.0%, from the first quarter of 2025; however, because tons sold declined 20.3%, labor cost per ton sold rose $4.92 as production at the mine outpaced coal sales.
26
Depreciation, Depletion and Amortization decreased by $5.6 million, or 57.1%, compared to the first quarter of 2025, partially attributable to the lower production during the first quarter of 2026. Following the impairment of our coal operations, the cost basis of our coal operations assets upon which depreciation, depletion and amortization is calculated was also lower resulting in significantly lower expense.
Interest expense decreased $1.2 million, or 59.4%, from $2.0 million for the three months ended March 31, 2025 to $0.8 million in 2026. The decrease is attributable to the paydown of the Company’s bank facility from $30.0 million at December 31, 2025 to zero at March 31, 2026.
Loss before income taxes narrowed by $2.1 million, or 41.4% compared to the first quarter of 2025. 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 2025
3rd 2025
4th 2025
1st 2026
T4Qs
Tons produced
1,059
1,034
905
907
3,905
Tons sold
890
1,355
995
4,094
Wash plant recovery in %
66
%
64
57
59
Capex (Coal Operations)
5,793
6,873
6,449
22,907
Capex per ton sold (Coal Operations)
6.51
5.07
6.48
4.44
5.60
Average cost per ton sold⁽ⁱ⁾
46.03
42.74
46.75
50.66
2nd 2024
3rd 2024
4th 2024
1st 2025
889
873
971
1,020
3,753
849
926
875
3,721
60
62
7,560
6,810
11,079
31,693
8.90
7.35
12.66
5.83
8.52
49.94
52.22
43.25
43.65
(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 divided by tons sold for the respective period in this table. Coal Operations costs are presented in the “Discussion and Analysis of our Reportable Segments” above.
EARNINGS (LOSS) PER SHARE
0.19
0.56
0.55
(0.27)
0.04
(5.06)
Our effective tax rate (“ETR”) is estimated at ~5.2% and ~0% for the three months ended March 31, 2026 and 2025, respectively. For the three months ended March 31, 2026, 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.
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RESTRICTED STOCK GRANTS
See “Item 1. Financial Statements - Note 8 - Stock Compensation Plans” for a discussion of restricted stock unit (“RSUs”).
MATERIAL CHANGES IN FINANCIAL CONDITION
Sources and Uses of Cash
We are a holding company that is dependent on the capital resources of our subsidiaries to satisfy our liquidity requirements at the corporate level. Each of our significant operating subsidiaries typically generate cash from operating activities, but our ability to access the liquidity of these and other subsidiaries may be limited by tax and legal considerations, and other factors.
Hallador had $43.4 million of cash and restricted cash as of March 31, 2026 versus $15.4 million at December 31, 2025.
Liquidity of Hallador
Our short-term sources of corporate liquidity include (i) cash and cash equivalents held by Hallador, (ii) cash provided by operations, (iii) interest income received on our cash and cash equivalents and, (iv) borrowing availability under our new credit facility. For the details of the borrowing availability under our credit facility, see “Item 1. Financial Statements - Note 4 – Bank Debt” to our unaudited condensed consolidated financial statements.
The liquidity of Hallador generally is used to fund (i) capital expenditures, (ii) debt service requirements and (iii) general and administrative expenses, as well as to settle certain obligations that are not included on our March 31, 2026 unaudited condensed consolidated balance sheet. In this regard, we have commitments related to (a) leases of railcars that qualify for the short-term lease exception and (b) certain operating costs associated with our Electric Operations and our Coal Operations.
From time to time, we may also require liquidity in connection with (i) acquisitions and other investment opportunities, (ii) the satisfaction of contingent liabilities, (iii) capital distributions to Hallador equity owners, (iv) the repayment of third party debt, or (v) income tax payments. No assurance can be given that any external funding would be available to us on favorable terms, or at all.
Consolidated Statement of Cash Flows Summary.
The first quarter of 2026 and 2025 unaudited condensed consolidated statements of cash flows are summarized as follows:
Change
(17,923)
4,192
37,668
23,937
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Operating Activities. The decrease in net cash provided by our operating activities is primarily attributable to the combination of (i) lower Adjusted EBITDA and related working capital items, (ii) increased inventory levels, (iii) incremental amortization of prepaid forward sales contracts for cash received in prior periods, and (iv) lower cash payments of interest, partially offset by incremental cash received for annual sales of accredited capacity compared to the first quarter of 2025. Consolidated Adjusted EBITDA is a non-GAAP measure, which investors should view as a supplement to, and not a substitute for, GAAP measures of performance included in our condensed consolidated statements of operations.
Investing Activities. The change in net cash used by our investing activities is primarily attributable to (i) a decrease in our capital expenditures of $4.0 million partially attributable to lower capitalization of mine development costs and (ii) a $0.2 million increase in the proceeds from sales of equipment.
For the three months ended March 31, 2026, capital expenditures (“Capex”) was $7.7 million allocated as follows (in millions):
Oaktown
3.8
Merom
2.3
Merom - ELG
1.3
ERAS Project
0.3
Capex per the condensed consolidated statements of cash flows
7.7
We expect our 2026 Capex to remain broadly stable as compared to our 2025 Capex, excluding any impacts of the ERAS Project. The actual amount of our 2026 Capex may vary from our expectations for a variety of reasons, including (i) changes in (a) the competitive or regulatory environment, (b) business plans, or (c) our expected future operating results and (ii) the availability of sufficient capital. Accordingly, no assurance can be given that our actual Capex will not vary materially from our expectations.
Financing Activities. The increase in net cash provided by our financing activities is primarily attributable to the net effect of (i) an increase in cash of $53.8 million from the net proceeds of the CMPO, (ii) a reduction in cash attributable to higher net repayments of bank debt of $9.0 million, and (iii) a decrease in cash from incremental lease financing payments of $1.5 million.
Capitalization
We seek to maintain our debt at levels that provide for equity returns without assuming undue risk. Our ability to service or refinance our debt and to maintain compliance with the leverage covenants in our credit agreement is dependent primarily on our ability to maintain or increase the Adjusted EBITDA of our consolidated businesses, maintain adequate liquidity and coverage of fixed charges, and to achieve adequate returns on our capital expenditures and acquisitions. Consolidated Adjusted EBITDA is a non-GAAP measure, which investors should view as a supplement to, and not a substitute for, GAAP measures of performance included in our condensed consolidated statements of operations. In addition, our ability to obtain additional debt financing is limited by the incurrence-based leverage covenants contained in our debt instruments. For example, if the Adjusted EBITDA of our business was to decline, our ability to obtain additional debt could be limited.
Prior to March 5, 2026, the Company was party to a credit agreement with PNC Bank, National Association (in its capacity as administrative agent, "PNC Bank"). As of December 31, 2025, our bank debt under the PNC Bank credit facility was $30.0 million, which was repaid subsequent to year-end as further described below.
On March 5, 2026, Hallador entered into a credit agreement with Texas Capital Bank and Old National Bank, among others, that replaces the Credit Agreement with PNC Bank and includes a $75.0 million revolving credit facility (the "New Revolving Credit Facility") and a $45.0 million delayed draw term loan (the "Delayed Draw Term Loan", and together with the New Revolving Credit Facility, the "New Credit Facility"). The New Credit Facility bears interest with margins ranging from 2.25% to 3.75% above SOFR or the applicable base rate, subject to a SOFR floor of 1.00%. The applicable margin is determined based upon the Company's leverage ratio and the type of loan drawn. The New Credit
29
Facility includes a commitment fee of 0.50% on any daily unused portions of the New Revolving Credit Facility. If the Delayed Draw Term Loan occurs, which is subject to meeting certain conditions, the principal balance of the Delayed Draw Term Loan shall be due and payable in equal quarterly installments of 2.5% of the original principal amount of such Delayed Draw Term Loan with a final payment of the remaining balance upon maturity. The New Credit Facility matures on March 5, 2029, and is collateralized by substantially all our assets. When drawn, the proceeds from the New Credit Facility may be used for ongoing working capital and general corporate purposes.
See “Item 1. Financial Statements - Note 4 – Bank Debt” to our unaudited condensed consolidated financial statements for additional discussion about our bank debt and related liquidity.
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 $18.0 million, including $6.3 million at Merom, presented as asset retirement obligations (“ARO”) 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.
CRITICAL ACCOUNTING ESTIMATES
For a description of our critical accounting policies and estimates, refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our 2025 Form 10-K. For a discussion of recent accounting pronouncements, newly adopted and recent accounting pronouncements not yet adopted, see “Note 2 – Recent Accounting Pronouncements” to the accompanying unaudited condensed consolidated financial statements included in Item 1 of this Quarterly Report. We did not have any material changes in critical accounting policies, estimates, judgments and assumptions during the three months ended March 31, 2026.
We are exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's power generation and mining activities, or with existing or forecasted financial or commodity transactions. The types of market risks that Hallador is exposed to are commodity price risk, interest rate risk, inflation risk, and counterparty credit risk.
Commodity Price Risk
Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities, and correlations between various commodities, such as natural gas, electricity, coal, oil, and emissions credits. We manage the commodity price risk of the Company's generation and mining operations by entering into various instruments to manage the variability in future cash flows from forecasted sales and purchases of power and fuel. These instruments include prepaid forward contracts, PPAs, and other bilateral agreements. Hallador uses these agreements to manage and fix the prices of certain purchases and sales to alleviate market risk and improve visibility into future results. See the “Forward Sales Position” table within the “Material Changes in Results of Operations” section of “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations”.
We are exposed to market price fluctuations for emission credits related to our investments in Sunrise Energy and Oaktown Gas, which had an aggregate value of $2.5 million at March 31, 2026. For additional information regarding our investments in Sunrise Energy and Oaktown Gas, see “Item 1. Financial Statements - Note 11. – Equity Method Investments” to our condensed consolidated financial statements.
Interest Rate Risk
We are exposed to changes in interest rates primarily as a result of our borrowing activities, which include instruments with variable rates. Our primary exposure to variable rates is through our SOFR-indexed credit facilities.
In general, we monitor the interest rate market and determine whether to enter into instruments to protect against increases in the interest rates on our variable-rate debt. From time to time, we may use interest rate swaps, interest rate cap, floor or collar agreements that lock in a maximum interest rate if variable rates rise, but also may allow our company to benefit, to a limited extent in the case of collars, from declines in market rates. We use judgment to determine the appropriate composition of interest rate derivative instruments, taking into account the relative costs and benefits in light of current and expected future market conditions, liquidity issues and other factors. As of March 31, 2026 and December 31, 2025, we did not hold any interest rate derivative instruments.
Weighted Average Variable Interest Rate. At March 31, 2026 and December 31, 2025, the outstanding principal amount of our variable-rate indebtedness aggregated zero and $30.0 million, respectively, and the weighted average interest rate (including margin) on such variable-rate indebtedness was approximately 7.16% and 8.17%, respectively, excluding the effects of interest rate derivative contracts, deferred financing costs, original issue premiums or discounts and commitment fees, all of which affect our overall cost of borrowing.
Inflation Risk
We are subject to inflationary pressures with respect to labor, procurement of electrical and mining equipment, and other costs. While we attempt to increase our revenue to offset increases in costs, there is no assurance that we will be able to do so. Therefore, costs could rise faster than associated revenue, thereby resulting in a negative impact on our operating results, cash flows and liquidity. The economic environment in which we operate is a function of government, economic, fiscal and monetary policies and various other factors beyond our control that could lead to inflation. We are unable to predict the extent that price levels might be impacted in future periods in the markets in which we operate.
Counterparty Credit Risk
We are exposed to the risk that the counterparties to our undrawn debt facilities and cash investments will default on their obligations to us. We manage these credit risks through the evaluation and monitoring of the creditworthiness of, and concentration of risk with, the respective counterparties. In this regard, credit risk associated with our undrawn debt facilities is spread across multiple counterparties, however notwithstanding, the default of certain counterparties could have a significant impact on our business. Most of our cash currently is invested in either (i) money market funds, including funds that invest in high-quality short-term instruments that preserve principal and offer daily liquidity, or (ii) overnight deposits with banks that transfer balances nightly into repurchase agreements collateralized by high-quality securities, including US government instruments. To date, neither the access to nor the value of our cash and cash equivalent balances have been adversely impacted by liquidity problems of financial institutions.
We invest our cash with financial institutions that meet high credit quality standards. We are exposed to the credit risk of these financial institutions and to interest rate risk in relation to the interest earning potential of our cash and cash equivalent balances. In order to mitigate these risks, we actively manage the deposits of our cash balances in light of our and our subsidiaries’ forecasted liquidity requirements.
At March 31, 2026 and December 31, 2025, our exposure to counterparty credit risk included (i) cash and cash equivalents and restricted cash of $43.4 million and $15.4 million, respectively, and (ii) aggregate availability of undrawn debt facilities of $60.8 million and $28.8 million, respectively.
While we currently have no specific concerns about the creditworthiness of any counterparty for which we have material credit risk exposures, we cannot rule out the possibility that one or more of our counterparties could fail or otherwise be unable to meet its obligations to us. Any such instance could have an adverse effect on our cash flows, results of operations, financial condition and/or liquidity.
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Although we actively monitor the creditworthiness of our key vendors, the financial failure of a key vendor could disrupt our operations and have an adverse impact on our revenue and cash flows.
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 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 upon that evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective for the purposes discussed above.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There have been no changes to our internal control over financial reporting during the quarter ended March 31, 2026, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.
See Item 1. Financial Statements - Note 14. – “Contingencies” to our condensed consolidated financial statements. Except as described therein, the Company is not currently a party to any legal proceedings that management believes, either individually or in the aggregate, would reasonably be expected to have a material adverse effect on the Company’s business, results of operations, financial condition, or liquidity.
There have been no material changes to the risk factors disclosed in Part I, Item 1A, "Risk Factors" in our Annual Report on Form 10-K for the fiscal year ended December 31, 2025, filed with the SEC on March 12, 2026.
During the three months ended March 31, 2026, all sales and issuances of the Company’s equity securities were registered under the Securities Act of 1933, as amended. Accordingly, during the period covered by this report, the Company did not engage in any unregistered sales of its equity securities that would be required to be disclosed pursuant to Item 701 of Regulation S-K. For a description of the Company’s registered equity issuances during the quarter, including shares issued under the ATM Program and the CMPO, see Item 1. Financial Statements - Note 15 – “At Market Agreement (“ATM”) and Confidentially Marketed Public Offering (“CMPO”)” to our condensed consolidated financial statements.
None.
See Exhibit 95.1 to this Form 10-Q for a listing of our mine safety violations.
Rule 10b5-1 Trading Arrangements
During the three months ended March 31, 2026, no director or officer of Hallador adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as each term is defined in Item 408 of Regulation S-K.
Exhibit No.
Document
1.1
Underwriting Agreement dated January 13, 2026(1)
10.1
Credit Agreement, dated March 5, 2026, among Hallador Energy Company, the lenders party thereto, the letter of credit issuers party thereto and Texas Capital Bank, as administrative agent incorporated by reference to Form 8-K filed on March 10, 2026 (2)
10.2
Master Power Purchase And Sale Agreement Long-Form Confirmation Letter dated May 1, 2026*
31.1
SOX 302 Certification - Chief Executive Officer*
31.2
SOX 302 Certification - Chief Financial Officer*
31.3
SOX 302 Certification – Chief Accounting 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)*
*Filed herewith.
(1) Incorporated by reference to Form 8-K filed on January 15, 2026.
(2) Incorporated by reference to Form 8-K filed on March 10, 2026.
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: May 6, 2026
/s/BRENT K. BILSLAND
Brent K. Bilsland, Chairman, President and CEO
/s/TODD E. TELESZ
Todd E. Telesz, CFO
/s/ERIC VAN DEMAN
Eric Van Deman, CAO