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, 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 May 8, 2025, we had 42,976,180 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
4
Condensed Consolidated Statements of Stockholders’ Equity
6
Notes to Condensed Consolidated Financial Statements
7
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
20
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
30
ITEM 4. CONTROLS AND PROCEDURES
31
PART II - OTHER INFORMATION
33
ITEM 4. MINE SAFETY DISCLOSURES
ITEM 6. EXHIBITS
SIGNATURES
34
ITEM 1. FINANCIAL STATEMENTS
Hallador Energy Company
(in thousands, except per share data)
(unaudited)
March 31,
December 31,
2025
2024
ASSETS
Current assets:
Cash and cash equivalents
$
6,891
7,232
Restricted cash
9,316
4,921
Accounts receivable
12,582
15,438
Inventory
36,318
36,685
Parts and supplies
40,137
39,104
Prepaid expenses
1,808
1,478
Total current assets
107,052
104,858
Property, plant and equipment:
Land and mineral rights
70,307
Buildings and equipment
435,329
429,857
Mine development
94,725
92,458
Finance lease right-of-use assets
13,034
Total property, plant and equipment
613,395
605,656
Less - accumulated depreciation, depletion and amortization
(360,624)
(347,952)
Total property, plant and equipment, net
252,771
257,704
Equity method investments
2,370
2,607
Other assets
3,904
3,951
Total assets
366,097
369,120
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of bank debt, net
16,965
4,095
Accounts payable and accrued liabilities
45,652
44,298
Current portion of lease financing
7,067
6,912
Contract liabilities - current
107,368
97,598
Total current liabilities
177,052
152,903
Long-term liabilities:
Bank debt, net
4,000
37,394
Long-term lease financing
6,921
8,749
Asset retirement obligations
15,386
14,957
Contract liabilities - long-term
42,539
49,121
Other
4,851
1,711
Total long-term liabilities
73,697
111,932
Total liabilities
250,749
264,835
Commitments and contingencies (Note 16)
Stockholders' equity:
Preferred stock, $.10 par value, 10,000 shares authorized; none issued
—
Common stock, $.01 par value, 100,000 shares authorized; 42,978 and 42,621 issued and outstanding, as of March 31, 2025 and December 31, 2024, respectively
430
426
Additional paid-in capital
190,378
189,298
Retained earnings (deficit)
(75,460)
(85,439)
Total stockholders’ equity
115,348
104,285
Total liabilities and stockholders’ equity
See accompanying notes to the condensed consolidated financial statements.
Three Months Ended March 31,
SALES AND OPERATING REVENUES:
Electric sales
85,943
60,681
Coal sales
30,185
49,630
Other revenues
1,659
1,263
Total sales and operating revenues
117,787
111,574
EXPENSES:
Fuel
15,210
8,059
Other operating and maintenance costs
28,389
37,262
Cost of purchased power
6,840
1,926
Utilities
4,152
4,594
Labor
27,029
35,168
Depreciation, depletion and amortization
14,977
15,443
Asset retirement obligations accretion
427
399
Exploration costs
21
70
General and administrative
6,825
5,944
Gain on disposal or abandonment of assets, net
(21)
(24)
Total operating expenses
103,849
108,841
INCOME FROM OPERATIONS
13,938
2,733
Interest expense (1)
(3,723)
(3,937)
Loss on extinguishment of debt
(853)
Equity method investment (loss)
(236)
(249)
NET INCOME (LOSS) BEFORE INCOME TAXES
9,979
(2,306)
INCOME TAX EXPENSE (BENEFIT):
Current
Deferred
(610)
Total income tax expense (benefit)
NET INCOME (LOSS)
(1,696)
NET INCOME (LOSS) PER SHARE:
Basic
0.23
(0.05)
Diluted
WEIGHTED AVERAGE SHARES OUTSTANDING
42,619
34,816
43,462
(1) Interest Expense:
Interest on bank debt
1,494
2,805
Other interest
1,732
728
Amortization:
Amortization of debt issuance costs
497
404
Total amortization
Total interest expense
3,723
3,937
3
(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
236
249
853
Cash paid on asset retirement obligation reclamation
(156)
(639)
Stock-based compensation
1,084
666
Amortization of contract liabilities
(35,669)
(24,529)
Accretion on contract liabilities
1,560
Change in current assets and liabilities:
2,856
5,709
367
(6,613)
(1,033)
(1,483)
(330)
(37)
3,124
(8,015)
Contract liabilities
37,297
35,355
3,224
937
Net cash provided by operating activities
38,419
16,369
(continued)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures
(11,693)
(14,874)
Proceeds from sale of equipment
24
Net cash used in investing activities
(11,672)
(14,850)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on bank debt
(33,000)
(26,500)
Borrowings of bank debt
12,000
Payments on lease financing
(1,693)
(1,238)
Proceeds from sale and leaseback arrangement
1,927
Issuance of related party notes payable
5,000
Debt issuance costs
(38)
ATM offering
6,580
Taxes paid on vesting of RSUs
(1)
Net cash used in financing activities
(22,693)
(2,270)
Increase (decrease) in cash, cash equivalents, and restricted cash
4,054
(751)
Cash, cash equivalents, and restricted cash, beginning of period
12,153
7,123
Cash, cash equivalents, and restricted cash, end of period
16,207
6,372
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH:
1,635
4,737
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest
1,830
3,083
SUPPLEMENTAL NON-CASH FLOW INFORMATION:
Change in capital expenditures included in accounts payable and prepaid expense
(1,649)
(5,290)
Stock issued on redemption of convertible notes and interest
9,721
5
Additional
Total
Common Stock Issued
Paid-in
Retained
Stockholders’
Shares
Amount
Capital
Earnings
Equity
Balance, December 31, 2024
42,621
Stock issued on vesting of RSUs
513
(5)
Net Income
Balance, March 31, 2025
42,978
Balance, December 31, 2023
34,052
341
127,548
140,699
268,588
321
(3)
(132)
Stock issued on redemption of convertible notes
1,582
15
9,706
Stock issued in ATM offering
711
6,573
Net loss
Balance, March 31, 2024
36,534
365
144,490
139,003
283,858
GENERAL BUSINESS
The condensed consolidated financial statements include the accounts of Hallador Energy Company (hereinafter known as “we, us, or our”) and its wholly owned subsidiaries Hallador Power Company, LLC (“Hallador Power”), Sunrise Coal, LLC (“Sunrise”), and Hourglass Sands, LLC (“Hourglass”), as well as Hallador Power and Sunrise’s wholly owned subsidiaries.
Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The Chief Operating Decision Maker (“CODM”), who is the Company’s Chief Executive Officer, reviews and assesses operating performance measures related to our Electric Operations and our Coal Operations segments.
In addition to these reportable segments, the Company has a “Corporate and Other and Eliminations” category, which is not significant enough, on a stand-alone basis, to be considered an operating segment. Corporate and Other and Eliminations primarily consist of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, LLC (“Sunrise Energy”), a private gas exploration company with operations in Indiana and Oaktown Gas, LLC, which we account for using the equity method.
The Electric Operations reportable segment includes electric power generation facilities of the Merom Power Plant (“Merom”).
The Coal Operations reportable segment includes our currently operating underground mining complex Oaktown 1. We have other mining complexes and locations which were idled during the year ended December 31, 2024.
All significant intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to the Company’s prior period condensed consolidated financial information to conform to the current period presentation. These presentation changes did not impact the Company’s condensed consolidated net income (loss), consolidated cash flows, total assets, total liabilities or total stockholders’ equity.
The interim financial data is unaudited; however, in our opinion, it includes all adjustments, consisting only of normal recurring adjustments necessary for a fair statement of the results for the interim periods. The condensed consolidated financial statements included herein have been prepared pursuant to the Securities and Exchange Commission’s (the “SEC”) rules and regulations; accordingly, certain information and footnote disclosures normally included in generally accepted accounting principles (“GAAP”) financial statements have been condensed or omitted.
The results of operations and cash flows for the three months ended March 31, 2025, are not necessarily indicative of the results to be expected for future quarters or for the year ending December 31, 2025.
Our organization and business, the accounting policies we follow, and other information are contained in the notes to our consolidated financial statements filed as part of our 2024 Annual Report on Form 10-K. This quarterly report should be read in conjunction with such Annual Report on Form 10-K.
(2)
RECENT ACCOUNTING PRONOUNCEMENTS
Recent Accounting Pronouncements - Adopted
For the year ended December 31, 2024, the Company retrospectively adopted Accounting Standards Update ("ASU") 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures ("ASU 2023-07"). See “Note 14 – Segments of Business” for enhanced disclosures associated with the adoption of ASU 2023-07.
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.
LONG-LIVED ASSET IMPAIRMENTS
During the year ended December 31, 2024, the Company recorded a $215.1 million non-cash impairment charge in our Coal Operations segment due to the results of our annual business plan review. As part of that business plan review, the Company evaluated core hole samples at several of our mines, noting the samples obtained at our Oaktown 2 mine were determined to be of a lower quality and density than that of the Oaktown 1 mine. As such, the Company decided to temporarily seal the Oaktown 2 mine, and to focus coal production at the Oaktown 1 mine, which has lower recovery costs.
The fair values of the impaired assets were determined using a discounted cash flow model, which represents Level 3 fair value measurements under the fair value hierarchy. The fair value analysis used assumptions regarding the projected economics of the Coal Operations assets, given prevailing commodity prices and operating expense levels.
For the three months ended March 31, 2025 and 2024, no impairment charges were recorded for long-lived assets.
(4)
INVENTORY
Inventory is valued at a lower of cost or net realizable value (NRV). As of March 31, 2025, and December 31, 2024, coal inventory includes NRV adjustments of $0.1 million and $0.3 million, respectively.
BANK DEBT
On September 27, 2024, the Company executed the First Amendment (“First Amendment”) to the Fourth Amended and Restated Credit Agreement, dated as of August 2, 2023 (as amended, the “Credit Agreement”), with PNC Bank, National Association (in its capacity as administrative agent, "PNC"), which was accounted for as a debt modification. The primary purpose of the First Amendment was to provide the Company with short-term covenant relief to pursue
8
additional liquidity. The First Amendment provides for additional flexibility for the Company to enter into prepaid forward power sale contracts, provided that the Company repays outstanding term loans under the Credit Agreement (“Term Loan”) with proceeds received from certain eligible power purchase agreements, up to a maximum of $20.0 million. These required prepaid forward power sale Term Loan repayments, if any, will take the place of the $6.5 million quarterly Term Loan payments. During the fourth quarter of 2024, the Company entered into a prepaid forward power sales contract in which $20.0 million of the proceeds were used to pay our required $6.5 million quarterly loan payments through the third quarter of 2025 and also reduced our fourth quarter 2025 payment to $6.0 million. Furthermore, the First Amendment defines certain administrative changes which include, among other things, added requirements related to reporting, third party financial advisors, and appraisals on coal and power assets.
Bank debt reduced by $21.0 million during the three months ended March 31, 2025. Bank debt totaled $23.0 million and is comprised of our Term Loan ($19.0 million as of March 31, 2025) and a $75.0 million revolver ($4.0 million borrowed as of March 31, 2025) under the Credit Agreement. Our debt is recorded at amortized cost, which approximates fair value due to the variable interest rates in the agreement and is collateralized primarily by our assets.
Liquidity
As of March 31, 2025, we had additional borrowing capacity of $52.8 million under the revolver and total liquidity of $69.0 million. Our additional borrowing capacity is net of $18.2 million in outstanding letters of credit as of March 31, 2025 that were required to maintain surety bonds. Liquidity consists of our additional borrowing capacity and cash and cash equivalents.
Fees
Unamortized bank fees and other costs incurred in connection with our initial facility totaled $4.3 million. Additional costs incurred with the First Amendment totaled $0.6 million. These unamortized bank fees were deferred and are being amortized over the term of the loan. Unamortized bank fees as of March 31, 2025, and December 31, 2024, were $2.0 million and $2.5 million, respectively.
Bank debt, less debt issuance costs, is presented below (in thousands):
Current bank debt
19,000
6,000
Less unamortized debt issuance cost
(2,035)
(1,905)
Net current portion
Long-term bank debt
38,000
(606)
Net long-term portion
Total bank debt
23,000
44,000
Less total unamortized debt issuance cost
(2,511)
Net bank debt
20,965
41,489
Future Maturities (in thousands):
2026
17,000
9
Covenants
The First Amendment, among other things, provided the Company with short-term covenant relief to pursue additional liquidity. The First Amendment waived the Company’s Leverage Ratio requirement for the third and fourth quarters of 2024, increased the threshold to 5.50 to 1.00 for the first quarter of 2025, and decreased the threshold back to 2.25 to 1.00 for each fiscal quarter thereafter. Additionally, the Debt Service Coverage Ratio requirement (1.25 to 1.00) was waived from third quarter of 2024 through the first quarter of 2025. The First Amendment also added additional financial covenants which include: (i) a maximum First Lien Leverage Ratio for the first quarter of 2025, calculated as of the end of each fiscal quarter for the trailing twelve months, not to exceed 3.50 to 1.00; (ii) a minimum liquidity requirement of $10.0 million, beginning on the First Amendment execution date and ending when the second quarter of 2025 compliance certificate is received; and (iii) a minimum quarterly EBITDA requirement, as defined in the First Amendment, of $5.0 million for the third quarter of 2024 through the first quarter of 2025.
As of March 31, 2025, our Leverage Ratio and First Lien Leverage Ratios were 1.89, liquidity of $69.0 million and quarterly adjusted EBITDA of $19.3 million were in compliance with the requirements of the Credit Agreement.
As of March 31, 2025, we were in compliance with all other covenants defined in the Credit Agreement.
Interest Rate
The interest rate on the facility ranges from secured overnight financing rate (“SOFR”) plus 4.00% to SOFR plus 5.00%, depending on our Leverage Ratio. As of March 31, 2025, we were paying SOFR plus 5.00% on the outstanding bank debt which equates to an all-in rate of 9.45%.
(6)
ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
Accounts payable and accrued liabilities consist of the following for the indicated dates (in thousands):
Accounts payable
26,002
24,291
Accrued property taxes
4,671
4,185
Accrued payroll
4,374
3,258
Workers' compensation reserve
4,805
4,321
Group health insurance
1,650
1,700
Asset retirement obligation - current portion
1,697
1,952
2,453
4,591
Total accounts payable and accrued liabilities
(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.
10
Accordingly, we concluded that a PPA that is not determined to be a lease or derivative constitutes a valid contract under ASC 606.
We recognize revenue daily, based on an output method of capacity made available as part of any stand-ready obligations for contract capacity performance obligations and daily, based on an output method of MWh of electricity delivered.
For the delivered energy performance obligation in the PPA with Hoosier, we recognize revenue daily for actual delivered electricity plus the amortization of the contract liability as a result of the Asset Purchase Agreement with Hoosier. For delivered energy to all other customers, we recognize revenue daily for the actual delivered electricity.
When energy hours at the Merom Hub are priced below our production cost or during outages at our Merom Facility, we have the option to make net hourly purchases of power in the MISO market. We record these as “Cost of purchased power” on our condensed consolidated statements of operations.
Coal operations
Our coal revenue is derived from sales to customers of coal produced at our facilities. Our customers typically purchase coal directly from our mine sites where the sale occurs and where title, risk of loss, and control pass to the customer at that point. Our customers arrange for and bear the costs of transporting their coal from our mines to their plants or other specified discharge points. Our customers are typically domestic utility companies. Our coal sales agreements with our customers are fixed-priced, fixed-volume supply contracts, or include a pre-determined escalation in price for each year. Price re-opener and index provisions may allow either party to commence a renegotiation of the contract price at a pre-determined time. Price re-opener provisions may automatically set a new price based on the prevailing market price or, in some instances, require us to negotiate a new price, sometimes within specified ranges of prices. The terms of our coal sales agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary by customer.
Coal sales agreements will typically contain coal quality specifications. With coal quality specifications in place, the raw coal sold by us to the customer at the delivery point must be substantially free of magnetic material and other foreign material impurities and crushed to a maximum size as set forth in the respective coal sales agreement. Price adjustments are made and billed in the month the coal sale was recognized based on quality standards that are specified in the coal sales agreement, such as Btu factor, moisture, ash, and sulfur content, and can result in either increases or decreases in the value of the coal shipped.
Disaggregation of Revenue
Revenue is disaggregated by revenue source for our electric operations and by primary geographic markets for our coal operations, as we believe this best depicts how the nature, amount, timing, and uncertainty of our revenue and cash flows are affected by economic factors.
Delivered energy (including contract liability amortization)
72,136
48,908
Capacity
13,807
11,773
Total Electric Operations sales
11
Outside third-party Indiana customers
20,314
18,103
Customers in Florida, North Carolina, Alabama and Georgia
9,871
31,527
Total Coal Operations sales
Performance Obligations
Electric Operations
We concluded that each megawatt hour (“MWh”) of delivered energy is capable of being distinct as a customer could benefit from each on its own by using/consuming it as a part of its operations. We also concluded that the stand-ready obligation to be available to provide electricity is capable of being distinct as each unit of capacity provides an economic benefit to the holder and could be sold by the customer.
Coal Operations
A performance obligation is a promise in a contract with a customer to provide distinct goods or services. Performance obligations are the unit of account for purposes of applying the revenue recognition standard and therefore determine when and how revenue is recognized. In most of our coal contracts, the customer contracts with us to provide coal that meets certain quality criteria. We consider each ton of coal a separate performance obligation and allocate the transaction price based on the base price per the contract, increased or decreased for quality adjustments.
The following table illustrates the balance of all current Electric and Coal Operations contracts allocated to performance obligations that are unsatisfied or partially unsatisfied as of March 31, 2025 and disaggregated by segment and contract duration.
2027
2028
2029
Delivered energy revenues
113,090
149,280
97,290
57,700
13,860
431,220
Capacity revenues
45,450
61,540
51,400
37,330
3,470
199,190
Coal Operations revenues
112,600
138,730
141,850
29,500
422,680
Total revenue (1)
271,140
349,550
290,540
124,530
17,330
1,053,090
(1) Coal revenues consist of consolidated revenues excluding our intercompany revenues from Merom.
Contract Balances
Under ASC 606, the timing of when a performance obligation is satisfied can affect the presentation of accounts receivable, contract assets, and contract liabilities. The main distinction between accounts receivable and contract assets is whether consideration is conditional on something other than the passage of time. A receivable is an entity’s right to consideration that is unconditional.
Under the typical payment terms of our contracts with customers, the customer pays us the contracted price for electricity or capacity. For coal contracts, the customer pays us a base price for the coal, increased or decreased for any quality adjustments. Amounts billed and due are recorded as trade accounts receivable and included in accounts receivable in our condensed consolidated balance sheets. Payments received prior to fulfilling our performance obligations are included in contract liabilities in our condensed consolidated balance sheets.
12
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
14,228
As the Company fulfills its contractual obligations, we recognized those amounts in revenues. The following table reconciles our beginning and ending contract liabilities for the periods presented (in thousands):
Total contract liabilities - beginning balance
146,719
113,741
Cash payments received on future contract obligations
37,296
Revenue recognized, cash payment received in prior period
(35,668)
Total contract liabilities - ending balance
149,907
124,567
(8)
INCOME TAXES
For the three months ended March 31, 2025 and 2024, we recorded income taxes using an estimated annual effective tax rate based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate. The effective tax rate for the three months ended March 31, 2025 and 2024, was 0% due to recording of a full valuation allowance and ~26%, respectively. Historically, our actual effective tax rates have differed from the statutory effective rate primarily due to the benefit received from statutory percentage depletion in excess of tax basis. The deduction for statutory percentage depletion does not necessarily change proportionately to changes in income (loss) before income taxes.
(9)
STOCK COMPENSATION PLANS
Non-vested grants as of December 31, 2024
1,034,486
Vested - weighted average share price on vested date was $12.28
(513,068)
Forfeited
(7,000)
Non-vested grants as of March 31, 2025
514,418
For the three months ended March 31, 2025 and 2024, our stock compensation expense was $1.1 million and $0.7 million, respectively.
Non-vested RSU grants will vest as follows:
Vesting Year
RSUs Vesting
162,000
176,210
176,208
The outstanding RSUs have a value of $6.3 million based on the March 31, 2025 closing stock price of $12.28.
As of March 31, 2025, unrecognized stock compensation expense to be recognized over the rolling 3-year vesting period is $1.5 million, and we had 217,319 RSUs available for future issuance. RSUs are not allocated earnings and losses as they are considered non-participating securities. Forfeitures are recognized as they occur.
13
(10)
SELF-INSURANCE
We self-insure our non-leased underground mining equipment. Such equipment was allocated among four mining units dispersed over seven miles, at March 31, 2025 and December 31, 2024. The historical cost of such equipment was approximately $160.8 million and $227.8 million as of March 31, 2025, and December 31, 2024.
We also self-insure for workers’ compensation claims under a guaranteed cost program. Under this program, we are responsible for the first $1.0 million per claim up to an aggregate of $4.0 million annually. Restricted cash of $3.3 million and $3.4 million as of March 31, 2025, and December 31, 2024, respectively, represents cash held and controlled by a third party and is restricted primarily for future workers’ compensation claim payments. The Company had $4.8 million and $4.3 million of workers’ compensation reserve as of March 31, 2025 and December 31, 2024, respectively, in “accounts payable and accrued liabilities” on the condensed consolidated balance sheets.
(11)
FAIR VALUE MEASUREMENTS
We account for certain assets and liabilities at fair value. The hierarchy below lists three levels of fair value based on the extent to which inputs used in measuring fair value are observable in the market. We categorize each of our fair value measurements in one of these three levels based on the lowest level input that is significant to the fair value measurement in its entirety. These levels are:
Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. We have no Level 1 instruments.
Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. We have no Level 2 instruments.
Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). ARO liabilities use Level 3 non-recurring fair value measures.
Nonrecurring Fair Value Measurements
During the fourth quarter of 2024, the Company completed its review of the coal mining facilities and future mining plans. The impairment analysis was based upon the coal mining operating plans of the Company, market driven pricing and cost trends. As part of that analysis, the Company determined the carrying amount of its coal mining long-lived asset group was not recoverable and recorded a non-cash, long-lived asset impairment charge of $215.1 million in 2024.
The discounted cash flow model was calculated using projected economics for the Coal Operations assets, using the Company’s mining plan and reserve estimates to be mined and sold at prevailing commodity prices, operating expenses, and production cost levels, which are classified as Level 3 inputs.
Credit Risk
The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, and restricted cash.
The Company’s cash and cash equivalent and restricted cash balances on deposit with financial institutions total $16.2 million and $12.2 million as of March 31, 2025 and December 31, 2024, respectively, which exceeded FDIC insured limits. The Company regularly monitors these institutions’ financial condition. The Company utilizes large and reputable banking institutions which it believes mitigates these risks. The Company has not experienced any losses in such accounts.
14
(12)
EQUITY METHOD INVESTMENTS
We own a 50% interest in Sunrise Energy, LLC, which owns gas reserves and gathering equipment with plans to develop and operate such reserves. Sunrise Energy, LLC, also plans to develop and explore for oil, natural gas, and coal-bed methane gas reserves on or near our underground coal reserves. The carrying value of the investment included in our condensed consolidated balance sheets as of March 31, 2025, and December 31, 2024, was $2.0 million and $2.1 million, respectively.
The Company also owns a 50% interest in Oaktown Gas, LLC. Oaktown Gas, LLC operates an emission abatement project through the destruction of gases extracted from the Oaktown mines to generate carbon credits and other emissions offset credits. The carrying value of the investment included in the condensed consolidated balance sheets as of March 31, 2025, and December 31, 2024, was $0.4 million and $0.5 million, respectively.
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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 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 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.
Presented below are the Electric and Coal Operations key metrics reviewed by the CODM at March 31, 2025 (in thousands):
Delivered Energy
Coal Sales
54,774
Capacity Revenue
Electric Sales
(38,071)
Other Operating Costs (1)
Total Variable Costs
(38,079)
Other Operating and Maintenance Costs (2)
(4,527)
(556)
Cost of Purchased Power
(6,840)
Other Operating and Maintenance Costs
(23,854)
(676)
(3,476)
(8,143)
(18,886)
Power Margin Without General and Administrative
27,678
Coal Margin Without General and Administrative
8,002
General and Administrative
(1,535)
(2,313)
Electric Operations — EBITDA Margin
26,143
Coal Operations — EBITDA Margin
5,689
(1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.
(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1).
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Presented below are the Electric and Coal Operations key metrics reviewed by the CODM at March 31, 2024 (in thousands):
66,036
(24,435)
(493)
(24,928)
(4,886)
(1,235)
(1,926)
(31,791)
(302)
(4,292)
(7,683)
(27,485)
20,956
1,233
(1,058)
(2,438)
19,898
(1,205)
Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues at March 31, 2025 (in thousands):
Corporate and Other
Reconciliation of Revenue:
and Eliminations
Consolidated
Other Operating Revenue
87
1,324
248
Coal Sales (Third-Party)
Coal Sales (Intercompany)
24,589
(24,589)
Operating Revenues
86,030
56,098
(24,341)
Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues at March 31, 2024 (in thousands):
157
810
296
16,406
(16,406)
60,838
66,846
(16,110)
17
Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes at March 31, 2025 (in thousands):
Reconciliation of Income (Loss) before Income Taxes:
23,417
49,560
(18,900)
Depreciation, Depletion and Amortization
(5,161)
(9,797)
(19)
(14,977)
Asset Retirement Obligations Accretion
(120)
(307)
(427)
Exploration Costs
Gain (loss) on disposal or abandonment of assets, net
Interest Expense
(1,732)
(1,991)
Equity Method Investment (Loss)
Corporate — General and Administrative
(2,977)
Income (Loss) before Income Taxes
19,217
(5,082)
(4,156)
Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes at March 31, 2024 (in thousands):
17,611
37,509
(17,611)
(4,697)
(10,728)
(18)
(15,443)
(111)
(288)
(399)
(70)
(148)
(3,209)
(580)
Loss on Extinguishment of Debt
(2,448)
Corporate — Other Operating and Maintenance Costs
(92)
15,099
(14,666)
(2,739)
Presented below are our Electric and Coal Operations assets and capital expenditures at March 31, 2025 (in thousands):
Other Reconciliations:
Assets
222,865
141,023
2,209
Capital Expenditures
5,449
6,244
11,693
Presented below are our Electric and Coal Operations assets and capital expenditures at March 31, 2024 (in thousands):
211,116
370,292
4,012
585,420
6,242
8,632
14,874
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(15)
NET INCOME (LOSS) PER SHARE
The following table (in thousands, except per share amounts) sets forth the computation of basic earnings (loss) per share for the periods indicated:
Basic earnings per common share:
Net income (loss) - basic
Weighted average shares outstanding - basic
Basic earnings (loss) per common share
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
(16)
CONTINGENCIES
Our Coal Operations subsidiary is party to litigation in which the plaintiffs allege violations of the Fair Labor Standards Act and state law due to alleged failure to compensate for time "donning" and "doffing" equipment and to account for certain bonuses in the calculation of overtime rates and pay. In January 2025, we agreed to settle with the plaintiffs such litigation for $2.8 million, which was recorded in “Operating expenses” on our consolidated statements of operations for the year ended December 31, 2024 and is in “Accounts payable and accrued liabilities” on our condensed consolidated balance sheets at March 31, 2025.
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THE FOLLOWING DISCUSSION UPDATES THE MD&A SECTION OF OUR 2024 ANNUAL REPORT ON FORM 10-K AND SHOULD BE READ IN CONJUNCTION THEREWITH.
We are very pleased with our first quarter results. Building on the progress we made throughout 2024 in transitioning our company from a bituminous coal producer to an integrated independent power producer (“IPP”), our quarterly results showed the upside of this strategy and business model. As gas inventories dropped and colder weather prevailed, we benefitted from higher energy prices and delivered energy volumes during January and February. We also saw improvements in our coal production throughout the first three months of the year as our 2024 restructuring efforts continue to take hold. During the quarter, we generated $117.8 million of revenue generating $19.3 million of adjusted EBITDA, an improvement of $6.2 million and $12.5 million, respectively, over the same period a year ago.
The Company continued to leverage the strong relationships we built with multiple counterparties, allowing us to supplement periods of weaker pricing with limited sales of firm energy. These firm energy sales help to mitigate the impacts of inconsistent weather and fluctuating natural gas prices and allowed us to focus on maximizing the value of our Merom Power Plant in a way that balances challenging periods while also giving us flexibility to capture upside opportunity in periods of elevated pricing, like we saw throughout January and February.
With respect to our ongoing negotiations with a leading global data center developer for the supply of a significant portion of our plant's output of capacity and energy for well over a decade, we believe that we continue to make meaningful progress towards the execution of definitive agreements. Our partner has made substantial investment with Hallador through the purchase of an exclusivity agreement which we disclosed last quarter, and with other stakeholders through payments and agreements to secure land, transmission capacity and equipment in support of the potential transaction. As we have previously disclosed, the exclusivity period runs through the beginning of June 2025. As we also highlighted in previous disclosures, these types of deals are inherently complex and involve multiple parties, which adds time and alignment challenges to the negotiation process. Despite these challenges, we remain encouraged by our partners and the steady progress that we continue to make towards definitive agreements. That said, it is uncertain that the definitive agreements will be executed by the expiration of the current exclusivity period. We are presently evaluating our counterparty’s request to extend the exclusivity period versus entertaining other opportunities while concurrently moving our original deal forward on a non-exclusive basis. While we remain encouraged by our progress and still believe that our current development partner represents a tremendous long-term opportunity for our company and its shareholders, we would be remiss to ignore the high level of interest that we have seen from third parties that would like to discuss alternative opportunities if we are ultimately unable to finalize definitive agreements with our current partner. Taken as a whole, we firmly believe that, in the end, we will forge a strategic partnership that will create significant value for years to come.
In the past, we highlighted our belief that the prevailing industry trend of retiring dispatchable generators, including coal, in favor of non-dispatchable resources such as wind and solar will lead to an unbalanced energy equation and extended volatility in the energy markets. We believe this volatility has the potential to make the attributes of our subsidiary, Hallador Power, much more valuable due to the enhanced reliability we provide versus non-dispatchable generators. In light of this, we continue to evaluate how to further enhance this value. Consistent with this belief, we are actively seeking opportunities to acquire additional dispatchable generation, which should help diversify our risk and provide opportunities to upsize the strategic deals that we continue to evaluate. We believe that this approach enhances our financial flexibility and strengthens our position in the evolving energy market.
We continue to study the benefits of not only adding additional generation through acquisition or expansion, but the potential of enhancing the reliability, resiliency and flexibility of our current plant by adding natural gas co-firing and creating a dual fuel scenario. While we are still in the evaluation process, and we recognize the tremendous amount of work that is required to accomplish such a transition, by adding the capability to co-fire with gas or coal, we believe that it will lead to opportunities where the counterparty desires to limit the amount of coal fired electricity that they are purchasing, while also providing Hallador the ability to take advantage of the best fuel cost scenario and better control our operating expenses across multiple fuel scenarios. Additionally, we believe that the ability to co-fire with natural gas
and/or coal will also provide increased resiliency in times where gas availability is limited, as we have seen in various winter storms across the last several years. This co-firing also allows us to retain the advantage of operating our Sunrise Coal subsidiary and leveraging our own coal supply to prevent unreasonable price increases by third party providers while simultaneously supporting our workforce and the surrounding community.
As we look to the future, our Merom Power Plant can produce up to 6 million MWh annually. The forward power price curves indicate that the margins earned on energy produced at Merom and the value of the accredited capacity sales assigned to the plant continue to increase, as we saw in the most recent MISO auction, where accredited capacity sold at prices in excess of $600 per MW Day in high demand seasons. We are seeing strong indications for both energy and capacity sales in 2025 and beyond and remain excited by our negotiations related to supporting data center development within the State of Indiana for many years to come.
We believe that our approach should allow Hallador Power to capture higher prices and energy volumes in the future versus what we have historically achieved since buying the plant in late 2022, specifically as we look to 2027 and beyond. Following the end of the quarter, we completed maintenance on one of the units at the plant and now have that unit back in service. We currently have a second unit out of service for scheduled maintenance and expect that unit to be back online early in the third quarter. We typically choose the shoulder season periods for these scheduled maintenance outages as power demand and pricing in spring are traditionally lower than in other parts of the year. We also try to limit our firm electricity sales during these periods to guard against any unforeseen or forced outages, which have the potential to expose us to spot market pricing. Despite these outages, we have contracted approximately 3.0 million MWh for the remainder of 2025 at an average price of $37.20/MWh, which should help to smooth our exposure to the spot market throughout the remainder of the year. For 2026, we currently have contracted 3.4 million MWh at an average sales price of $44.43/MWh and continue to see high demand. Following 2026, we are optimistic that we can sell energy at higher prices in support of data center development and/or to traditional wholesale customers in line with the indicators of a higher forward curve.
As we said on March investor call, we continue to evaluate other strategic transactions that could add durability, scale, and geographic expansion opportunities to our electric operations. We believe that Hallador is uniquely positioned to transform retiring and/or underperforming assets into future opportunities. This will enable us to supply high demand end users, such as data centers and on-shored industrial customers, with minimal impact to retail consumers. By continuing the operations of the dispatchable plants to support large load industrial users as the utilities transition to non-dispatchable generation, the new generation becomes additive to the struggling grid rather than cannibalizing the overall reliability of what exists today. We are optimistic about the potential to add to our strategic portfolio and the long-term benefits that such a transaction could produce for the company, its shareholders and its customers. This model for growth enables us to continue our shift away from the less favorable pricing related to plant acquisition, to traditional wholesale market pricing, and ultimately to the enhanced pricing associated with supporting data centers and other large load end users. Importantly, the positive momentum that we are seeing from the current administrations on both the federal and state levels should make transactions of this sort more feasible than they would have been under the prior administrations.
Shifting to our coal operations, we continue to see improvements from the restructuring of our Sunrise Coal division that we initially announced in the first quarter of 2024. We spent much of last year optimizing production, headcount, and strategy to best support our electric operations and our existing third-party coal contracts. As we look to the future, this restructuring should provide us with greater flexibility to quickly scale if we see coal prices increase to a point that justifies restarting production at our more expensive units.
With renewed support of coal mining and coal fired power generation on both the federal and state level, we believe that we are positioned well to take advantage of opportunities for growth and/or expansion. Current market dynamics have improved over where they were last year, and if this trend continues, it has the potential to encourage us to bring on additional coal production in the back half of 2025 and/or 2026. Notwithstanding this potential to increase production, we currently expect to produce approximately 3.8 million tons of coal in 2025. In the first quarter of 2025, we produced approximately 1.0 million tons of coal at our Oaktown Mining Complex and shipped approximately 1.1 million tons to Merom and other customers. We use supplemental coal from third party suppliers typically purchased at favorable prices to diversify self-production supply risk and to provide us additional flexibility in our sales portfolio. The optionality to
obtain low-cost tons either internally or from third parties while capturing upward swings in the commodity markets for coal should further maximize margins while optimizing fuels costs at Merom.
We remain excited about the continued and deliberate transformation of Hallador from a commodity focused producer of coal to an IPP. We believe this transition provides a significant opportunity to capture the expanding margins of the energy markets and capitalize on the soaring demand for electricity. We are pleased by the strong interest we continue to see from potential counterparties in our energy and capacity offerings, bolstered by Indiana’s efforts to attract data centers and other high-density power users through its business-friendly climate and favorable tax policies. The support of the coal industry by the Trump administration throughout the first quarter should also help to dampen the headwinds we were previously facing and provide flexibility as we continue our strategic transition in support of the economy’s insatiable appetite for reliable energy that we see advancing every day. We continue to believe that our business model positions us well to materially strengthen our opportunities for growth and cash flow generation.
Our goal is for Hallador Power to generate on average 1.5 million MWh on a quarterly basis, which equates to 6.0 million MWh annually (see Hallador Power’s capacity and utilization information below). During the first three months of the year, Hallador Power generated 1.4 million MWh, or 93.3% or our quarterly target and purchased 0.2 million MWh.
Power Capacity and Utilization
Nameplate capacity (MW)(i)
1,080
Accredited capacity for the period (MW)(ii)
845
836
Accredited capacity utilization(iii)
78
%
45
(i).
Nameplate capacity for the Merom Power Plant refers to the maximum electric output generated by the plant in the period presented and may not reflect actual production. Actual production each period varies based on weather conditions, operational conditions, and other factors.
(ii).
Accredited capacity is based on MISO’s average seasonal accreditations for the year. Average seasonal accreditations were 775 MW and 829 MW per day for 2025 and 2024, respectively. Accreditations are weighted and adjusted annually based on 3-year rolling performance metrics.
(iii).
Accredited capacity utilization is measured as power produced (MWh) divided by accredited capacity for the period (MW) multiplied by 24, times the number of days for the period.
When forward selling Capacity, we target annual sales of around $65.0 million to offset our fixed annual costs at the plant of approximately $60.0 million. For 2025, we have contracted approximately $56.0 million or 86.2% of our target with $45.5 million remaining to be delivered in 2025. We believe our forward Capacity sales goals are attainable as illustrated in our “Solid Forward Sales Position” table below.
Our condensed consolidated financial statements should be read in conjunction with this discussion. This analysis includes a discussion of metrics on a per mega-watt hour (MWh) and a per ton basis as derived from the condensed consolidated financial statements, which are considered non-GAAP measurements. These metrics are significant factors in assessing our operating results and profitability.
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OVERVIEW
The following is an overview our Electric Operations and Coal Operations for Q1 2025 compared to Q4 2024.
I.
Q1 2025 Net Income of $10.0 million.
23
II.
Solid Forward Sales Position (unaudited)
Power
Energy
Contracted MWh (in millions)
3.04
3.36
1.78
1.09
0.27
9.54
Average contracted price per MWh
37.20
44.43
54.66
52.94
51.33
Contracted revenue (in millions)
113.09
149.28
97.29
57.70
13.86
431.22
Average daily contracted capacity MW
784
733
623
454
100
Average contracted capacity price per MWd
211
230
226
225
Contracted capacity revenue (in millions)
45.45
61.54
51.40
37.33
3.47
199.19
Total Energy & Capacity Revenue
Contracted Power revenue (in millions)
158.54
210.82
148.69
95.03
17.33
630.41
Coal
Priced tons - 3rd party (in millions)
2.21
2.50
0.50
7.71
Avg price per ton - 3rd party
50.95
55.49
56.74
59.00
Contracted coal revenue - 3rd party (in millions)
112.60
138.73
141.85
29.50
422.68
TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED
271.14
349.55
290.54
124.53
1,053.09
Priced tons - Intercompany (in millions)
1.82
2.30
8.72
Avg price per ton - Intercompany
51.00
Contracted coal revenue - Intercompany (in millions)
92.82
117.30
444.72
TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT
363.96
466.85
407.84
241.83
1,497.81
LIQUIDITY AND CAPITAL RESOURCES
Liquidity and Capital Resources
Material Off-Balance Sheet Arrangements
CAPITAL EXPENDITURES (capex)
For the three months ended March 31, 2025, capex was $11.7 million allocated as follows (in millions):
Oaktown – maintenance capex
4.0
Oaktown – investment
2.2
Merom Plant
5.5
Capex per the Condensed Consolidated Statements of Cash Flows
11.7
RESULTS OF OPERATIONS
Presentation of Segment Information
Our operations are divided into two primary reportable segments: Electric Operations and Coal Operations. The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are presented as “Corporate and Other and Eliminations” within the Notes to the Condensed Consolidated Financial Statements and primarily are comprised of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana and Oaktown Gas, LLC, which we account for using the equity method.
25
EBITDA Margin
Interest expense
(per MWh)
MWh Generated (in thousands)
1,422
816
MWh Purchased (in thousands)
143
75
MWh Sold (in thousands)
1,565
891
46.09
54.89
8.82
13.21
54.91
68.10
(24.33)
(27.42)
(0.01)
(0.55)
(2.89)
(5.48)
(4.37)
(2.16)
(0.43)
(0.34)
(5.20)
(8.62)
(0.98)
(1.19)
16.70
22.34
0.06
0.18
(3.30)
(5.27)
(0.08)
(0.12)
(1.11)
(0.17)
12.27
16.96
Q1 2025 vs. Q1 2024
Delivered Energy increased $23.2 million, or 47.5%, and we sold 0.7 million MWh more than we did in Q1 2024. These increases were due to $26.4 million in new revenue contracts starting in Q1 2025 that were not in effect during Q1 2024. During the quarter we experienced a significantly higher priced natural gas environment when compared to Q1 2024,
26
(average spot price for natural gas was up $2.02 per mbtu, or 94.7%, compared to Q1 2024). As natural gas is a competitor to coal, this price increase helped drive up the demand for Power during Q1 2025.
Fuel increased $13.6 million, or 55.8%, compared to the first quarter of 2024. Our generated MWh’s increased by 0.6 million MWh, or 74.3%, from the first quarter of 2024. We used 0.2 million tons, or 61.2%, more in production compared to the prior year. These increases were primarily related to our increased electricity sales which were partially offset by declines in coal market pricing. The average purchase price per ton of coal used in the plant on a segment basis, was $53.80 in the first quarter of 2025, decreasing from $57.45 per ton in the first quarter of 2024.
Cost of purchased power was $4.9 million during the first quarter of 2025. When energy hours at the Merom Hub are priced below our production cost or during outages at our Merom Facility, we have the option to make net hourly purchases of power in the MISO market, which we record as cost of purchased power. During the first quarter of 2025, we purchased 0.2 million MWh, an increase of 90.7% from Q1 2024, at an average price of $47.83 per MWh.
Interest expenses increased $1.6 million, or 1070.3%, compared to the first quarter of 2024. The increase in our interest expense primarily relates $1.2 million of accretion related to our to a prepaid delivered energy contract.
Income before income taxes increased $4.1 million, or 27.3%, compared to the first quarter of 2024. The main drivers of this change in income before income taxes are described in the discussion above.
556
1,235
23,854
31,791
3,476
4,292
18,886
27,485
2,313
2,438
(14,690)
(per ton)
Tons Sold
1,071
1,214
51.14
54.40
0.52
1.02
22.27
26.19
3.25
3.54
17.63
22.64
2.16
2.01
5.31
(0.99)
(9.15)
(8.84)
(0.29)
(0.24)
(0.02)
(0.06)
0.02
(1.86)
(2.64)
(5.98)
(12.77)
27
Coal sales decreased $11.3 million, or 17.1%, compared to the first quarter of 2024. Consolidated coal sales decreased $19.4 million, or 39.2%, from 2024. These declines were due to reductions in volume and average sales price for our coal. Our average sales price, on a segment basis, decreased $3.25 per ton and we sold 0.1 million tons less compared to 2024. Our average sales price, on a consolidated basis, for 2025 decreased $4.22 per ton and we sold 0.3 million tons less compared to 2024. Operating revenues for the first quarter of 2025 include $24.6 million in sales to the Merom plant which were eliminated in the consolidation.
Other operating and maintenance costs decreased $7.9 million, or 25.0%, compared to the first quarter of 2024. During the first quarter of 2025, we produced 0.3 million tons less on a segment basis than 2024. Labor decreased $8.6 million, or 31.3%, from 2024, and decreased $5.01 per ton sold. These changes were driven by the Reorganization Plan disclosed in “Note 13 — Organizational Restructuring” to the condensed consolidated financial statements. As part of the Organizational Restructuring, we incurred aggregate expenses of $1.1 million in the first quarter of 2024 that were included in coal operations “Labor”. These charges related to compensation, tax, professional, and insurance related expenses and are considered one-time charges paid during 2024. Additionally, we went from 5 mines producing to 1 mine producing and reduced our coal employee headcount by 201 employees.
Interest expense decreased $1.2 million, or 38.0%, compared to the first quarter of 2024. Our decreased interest expense relates to reductions of convertible debt of $11.0 million, related party debt of $5.0 million and bank debt of $54.0 million, from Q1 2024.
Loss before income taxes decreased $9.6 million, or 65.4%, compared to the first quarter of 2024. The main drivers of this change in loss before income taxes are described in the discussion above.
Quarterly coal sales and cost data on a segment basis are as follows (in thousands, except per ton data and wash plant recovery percentage):
All Mines
2nd 2024
3rd 2024
4th 2024
1st 2025
T4Qs
Tons produced
889
873
971
1,020
3,753
Tons sold
849
926
875
3,721
Wash plant recovery in %
59
60
62
64
Capex (Coal Operations)
7,560
6,810
11,079
31,693
Maintenance capex (Coal Operations)
6,014
4,208
4,492
18,714
Maintenance capex per ton sold (Coal Operations)
7.08
4.54
5.13
3.73
5.03
Average cost per ton sold⁽ⁱ⁾
49.94
52.22
43.25
43.65
2nd 2023
3rd 2023
4th 2023
1st 2024
1,723
1,594
1,331
1,271
5,919
1,714
2,054
1,461
6,443
67
65
14,445
11,570
17,867
52,514
9,754
7,938
13,567
8,085
39,344
Maintenance capex per ton (Coal Operations)
5.69
3.86
9.29
6.66
6.11
41.52
46.54
53.78
51.65
(i) Average cost per ton sold is calculated as the sum of the Coal Operation’s “Fuel”, “Other Operating and Maintenance Costs”, “Utilities” and “Labor” costs. Coal Operations costs are presented in the “Presentation of Segment Information” above.
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Presentation of Consolidated Information
EARNINGS (LOSS) PER SHARE
(0.27)
0.04
(5.06)
0.51
0.49
(0.31)
0.47
0.44
Our effective tax rate (ETR) is estimated at ~0% and ~26% for the three months ended March 31, 2025 and 2024, respectively. For the three months ended March 31, 2025, we estimated our annual ETR based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate. Our ETR differs from the statutory rate due primarily to statutory depletion in excess of tax basis and changes in the valuation allowance. The deduction for statutory percentage depletion does not necessarily change proportionately to changes in income (loss) before income taxes.
RESTRICTED STOCK GRANTS
See “Item 1. Financial Statements - Note 9 - Stock Compensation Plans” for a discussion of RSUs.
CRITICAL ACCOUNTING ESTIMATES
We believe that the estimates of coal reserves, asset retirement obligation liabilities, deferred tax accounts, valuation of inventory, and the estimates used in impairment analysis are our critical accounting estimates.
The reserve estimates are used in the depreciation, depletion, and amortization calculations and our internal cash flow projections. If these estimates turn out to be materially under or over-stated, our depreciation, depletion and amortization expense and impairment test may be affected. The process of estimating reserves is complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. The reserve estimates are prepared by professional engineers, both internal and external, and are subject to change over time as more data becomes available. Changes in the reserves estimates from the prior year were nominal.
SMCRA and similar state statutes require, among other things, that surface disturbance be restored in accordance with specified standards and approved reclamation plans. SMCRA requires us to restore affected surface areas to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations.
Obligations are reflected at the present value of their future cash flows. We reflect accretion of the obligations for the period from the date they are incurred through the date they are extinguished. The ARO assets are amortized using the units-of-production method over estimated recoverable (proven and probable) reserves. We use credit-adjusted risk-free discount rates ranging from 7% to 10% to discount the obligation, inflation rates anticipated during the time to reclamation, and cost estimates prepared by its engineers inclusive of market risk premiums. Activities include reclamation of pit and support acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and slurry ponds.
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Accretion expense is recognized on the obligation through the expected settlement date. On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing and extent of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Any difference between the recorded amount of the liability and the actual cost of reclamation will be recognized as a gain or loss when the obligation is settled.
We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. We believe that our income tax filing positions and deductions would be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position. We have not taken any significant uncertain tax positions, and our tax provisions and returns are prepared by a large public accounting firm with significant experience in energy related industries. Changes to the estimates from reported amounts in the prior year were not significant.
Inventory is valued at a lower of cost or net realizable value (NRV). Anticipated utilization of low sulfur, higher-cost coal from our Freelandville, and Prosperity mines has the potential to create NRV adjustments as our estimated needs change. The NRV adjustments are subject to change as our costs may fluctuate due to higher or lower production and our NRV may fluctuate based on sales contracts we enter into from time to time. As of March 31, 2025, and December 31, 2024, coal inventory includes NRV adjustments of $0.1 million and $0.3 million, respectively.
Long-lived assets used in operations are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The determination of the lowest level of cash flows is largely based on nature of production, common infrastructure, common sales points, common regulation and management oversight to make such determinations. These determinations could impact the determination and measurement of a potential asset impairment. Management evaluates assets for impairment through an established process in which changes to significant assumptions such as prices, volumes and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future volumes, commodity prices, operating costs and capital investment plans, considering all available information at the date of review. Changes to any of the market-based assumptions can significantly affect estimates of undiscounted and discounted pre-tax cash flows and impact the recognition and amount of impairments.
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 March 31, 2025, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.
FORWARD-LOOKING STATEMENTS
Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” These statements are based on our beliefs as well as assumptions made by, and information currently available to us. When used in this document, the words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “may,” “project,” “will,” and similar expressions identify forward-looking statements. Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements. These statements reflect our current views with respect to future events and are subject to numerous assumptions that we believe are open to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ from those in the forward-looking statements are:
If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement. When considering forward-looking statements, you should also keep in mind the risk factors described in “Item 1A. Risk Factors” in our Annual Report on Form 10-K. The risk factors could also cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments, unless required by law.
You should consider the information above when reading any forward-looking statements contained in this Quarterly Report on Form 10-Q; other reports filed by us with the U.S. Securities and Exchange Commission (“SEC”); our press releases; our website www.halladorenergy.com and written or oral statements made by us or any of our officers or other authorized persons acting on our behalf.
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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
97.1
Hallador Energy Company Policy for the Recovery of Erroneously Awarded Compensation (incorporated by reference to Exhibit 97.1 to the Form 10-K filed March 14, 2024)
101.INS
Inline XBRL Instance Document
101.SCH
Inline XBRL Schema Document
101.CAL
Inline XBRL Calculation Linkbase Document
101.LAB
Inline XBRL Labels Linkbase Document
101.PRE
Inline XBRL Presentation Linkbase Document
101.DEF
Inline XBRL Definition Linkbase Document
104
Cover Page Interactive Data File (embedded with the Inline XBRL document)
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 12, 2025
/s/ MARJORIE HARGRAVE
Marjorie Hargrave, CFO (Principal Financial Officer and Principal Accounting Officer)