Hallador Energy Company
05/06/2026 | Press release | Distributed by Public on 05/06/2026 15:21
Quarterly Report for Quarter Ending March 31, 2026 (Form 10-Q)
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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:
•Forward-Looking Statements. This section provides a description of certain factors that could cause actual results or events to differ materially from anticipated results or events.
•Overview. This section provides a general description of our business and recent events.
•Material Changes in Results of Operations. This section provides an analysis of our results of operations for the three months ended March 31, 2026 and 2025.
•Material Changes in Financial Condition. This section provides an analysis of our liquidity and our condensed consolidated statements of cash flows.
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:
| • | changes in macroeconomic and market conditions and market volatility, and the impact of such changes and volatility on our financial position; |
| • | fluctuations in weather, natural gas and electricity commodity costs, inflation and economic conditions that impact demand of our customers and our operating results; |
| • | the outcome or escalation of current international hostilities; |
| • | changes in competition, or changes in electricity, natural gas or coal prices, demand, and availability which could affect our operating results and cash flows; |
| • | risks associated with the expansion of our operations and properties; |
| • | risks relating to Midcontinent Independent System Operator's ("MISO") Expedited Resource Addition Study ("ERAS") program review and approval process; |
| • | risks relating to our ability to secure agreements in support of the development and construction of planned projects, including the expansion of the Merom Generating Station through the ERAS program; |
| • | legislation, regulations, administrative actions (e.g., executive orders), and court decisions and interpretations thereof, including those relating to the environment and the release of greenhouse gases ("GHG"), mining, miner health and safety, and health care, as well as those relating to data privacy protection; |
| • | deregulation of the electric utility industry or the effects of any adverse change in the coal industry, electric utility industry, or general economic conditions; |
| • | dependence on significant or long-term customer contracts, including renewing customer contracts upon expiration of existing contracts; |
| • | changes in the geopolitical environment in industries in which our customers operate; |
| • | changes in attitude toward environmental, social, and governance ("ESG") matters among regulators, investors and parties with which we do business; |
| • | the effect of changes in taxes or tariffs and other trade measures, including uncertainty regarding tariffs on imports into the United States, which could impact the Company's procurement and sourcing strategies; |
| • | risks relating to inflation and increasing interest rates; |
| • | liquidity constraints, including due to restrictions contained in our debt agreements or other arrangements and those resulting from any future unavailability of financing; |
| • | customer bankruptcies, a decline in customer creditworthiness, or customer cancellations or breaches to existing contracts, including failures to make payments when due; |
| • | customer delays or failure to take coal or electricity under contracts; |
| • | adjustments made in price, volume or terms to existing coal or electricity contracts; |
| • | our productivity levels and margins earned on our coal or electricity sales; |
| • | supply chain disruptions and changes in equipment, raw material, service or labor costs or availability, including due to inflationary pressures; |
| • | changes in the availability of skilled labor; |
| • | our ability to maintain satisfactory relations with our employees; |
| • | increases in labor costs, adverse changes in work rules, or cash payments or projections associated with workers' compensation claims; |
| • | increases in transportation costs and risk of transportation delays or interruptions; |
| • | operational interruptions due to geologic, permitting, labor, weather-related or other factors, including challenges in operating an aging coal-fired power plant; |
| • | risks associated with major mine-related or other accidents, mine fires, mine floods or other interruptions, including unanticipated operating conditions and other events that are not within our control; |
| • | results of litigation, including claims not yet asserted; |
| • | difficulty maintaining our surety bonds for mine reclamation; |
| • | decline in or change in the coal industry's share of electricity generation, including as a result of environmental concerns related to coal mining and combustion and the cost and perceived benefits of other sources of electricity, such as natural gas, nuclear energy, and renewable fuels; |
| • | risks resulting from natural disasters; |
| • | difficulty in making accurate assumptions and projections regarding landfill and mine reclamation; |
| • | uncertainties in estimating and replacing our coal reserves; |
| • | the impact of current and potential changes to federal or state tax rules and regulations, including the effects of the One Big Beautiful Bill Act ("OBBBA") or a loss or reduction of benefits from certain tax deductions and credits; |
| • | difficulty obtaining commercial property insurance; |
| • | evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions; |
| • | difficulty in making accurate assumptions and projections regarding future revenues and costs associated with equity investments in companies we do not control; and |
| • | other factors, including those discussed in "Item 1A. Risk Factors" in our 2025 Form 10-K. |
If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement. When considering forward-looking statements, you should also keep in mind the risk factors described in "Item 1A. Risk Factors" in our 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.
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)*
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2026 |
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2027 |
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2028 |
|
2029 |
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Total |
|||||
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Power |
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Accredited Capacity |
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|||||
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Average daily contracted accredited capacity MW |
|
781 |
|
782 |
|
668 |
|
340 |
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|
|||||
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Average contracted accredited capacity price per MWd |
|
$ |
246 |
|
$ |
264 |
|
$ |
300 |
|
$ |
398 |
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|
|
|
Contracted accredited capacity revenue (in millions) |
|
$ |
52.82 |
|
$ |
75.26 |
|
$ |
73.28 |
|
$ |
20.44 |
|
$ |
221.80 |
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Energy |
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|
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Contracted MWh (in millions) |
|
3.10 |
|
3.06 |
|
1.09 |
|
0.27 |
|
7.52 |
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Average contracted price per MWh |
|
$ |
43.74 |
|
$ |
46.50 |
|
$ |
52.94 |
|
$ |
51.33 |
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|
|
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Contracted revenue (in millions) |
|
$ |
135.59 |
|
$ |
142.29 |
|
$ |
57.70 |
|
$ |
13.86 |
|
$ |
349.44 |
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Total Accredited Capacity & Energy Revenue (in millions) |
|
$ |
188.41 |
|
$ |
217.55 |
|
$ |
130.98 |
|
$ |
34.30 |
|
$ |
571.24 |
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|
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Coal |
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Priced tons - 3rd party (in millions) |
|
2.10 |
|
2.50 |
|
0.50 |
|
|
|
|
5.10 |
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Avg price per ton - 3rd party |
|
$ |
55.73 |
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$ |
56.74 |
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$ |
59.00 |
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|
|
|
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Contracted coal revenue - 3rd party (in millions) |
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$ |
117.03 |
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$ |
141.85 |
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$ |
29.50 |
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$ |
- |
|
$ |
288.38 |
|
TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED |
|
$ |
305.44 |
|
$ |
359.40 |
|
$ |
160.48 |
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$ |
34.30 |
|
$ |
859.62 |
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Priced tons - Intercompany (in millions) |
|
2.08 |
|
2.30 |
|
3.17 |
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|
|
7.55 |
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Avg price per ton - Intercompany |
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$ |
51.00 |
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$ |
51.00 |
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$ |
51.00 |
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|
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Contracted coal revenue - Intercompany (in millions) |
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$ |
106.08 |
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$ |
117.30 |
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$ |
161.67 |
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$ |
- |
|
$ |
385.05 |
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TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT |
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$ |
411.52 |
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$ |
476.70 |
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$ |
322.15 |
|
$ |
34.30 |
|
$ |
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.
Electric Operations
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Three Months Ended March 31, |
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2026 |
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2025 |
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(in thousands) |
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Delivered Energy |
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$ |
49,562 |
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$ |
72,136 |
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Accredited Capacity Revenue |
|
|
15,534 |
|
|
13,807 |
|
|
Electric Sales |
|
$ |
65,096 |
|
$ |
85,943 |
|
|
|
|
|
|
|
|
|
|
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Fuel |
|
$ |
(27,527) |
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$ |
(38,071) |
|
|
Other Operating Costs (1) |
|
|
(29) |
|
|
(8) |
|
|
Other Operating and Maintenance Costs (2) |
|
|
(8,854) |
|
|
(4,527) |
|
|
Cost of Purchased Power |
|
|
(14,863) |
|
|
(6,840) |
|
|
Utilities |
|
|
(134) |
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|
(676) |
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|
Labor |
|
|
(8,129) |
|
|
(8,143) |
|
|
General and Administrative |
|
|
(1,310) |
|
|
(1,535) |
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Segment EBITDA |
|
|
4,250 |
|
|
26,143 |
|
|
Other Operating Revenue |
|
|
137 |
|
|
87 |
|
|
Depreciation, Depletion and Amortization |
|
|
(6,383) |
|
|
(5,161) |
|
|
Asset Retirement Obligations Accretion |
|
|
(131) |
|
|
(120) |
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|
Interest Income |
|
|
36 |
|
|
- |
|
|
Interest Expense |
|
|
(2,947) |
|
|
(1,732) |
|
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Income before Income Taxes |
|
$ |
(5,038) |
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$ |
19,217 |
|
(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.
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Three Months Ended March 31, |
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2026 |
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2025 |
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(per MWh) |
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MWh Generated (in thousands) |
|
|
938 |
|
|
1,422 |
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MWh Purchased (in thousands) |
|
|
183 |
|
|
132 |
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MWh Sold (in thousands) |
|
|
1,121 |
|
|
1,554 |
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|
|
|
|
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|
|
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Delivered Energy |
|
$ |
44.21 |
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$ |
46.42 |
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Accredited Capacity Revenue |
|
|
13.86 |
|
|
8.88 |
|
Electric Sales |
|
$ |
58.07 |
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$ |
55.30 |
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|
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|
|
|
|
|
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Fuel |
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$ |
(24.56) |
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$ |
(24.50) |
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Other Operating Costs (1) |
|
|
(0.03) |
|
|
(0.01) |
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Other Operating and Maintenance Costs (2) |
|
|
(7.90) |
|
|
(2.91) |
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Cost of Purchased Power |
|
|
(13.26) |
|
|
(4.40) |
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Utilities |
|
|
(0.12) |
|
|
(0.44) |
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Labor |
|
|
(7.25) |
|
|
(5.24) |
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General and Administrative |
|
|
(1.17) |
|
|
(0.99) |
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Segment EBITDA |
|
|
3.78 |
|
|
16.81 |
|
Other Operating Revenue |
|
|
0.12 |
|
|
0.06 |
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Depreciation, Depletion and Amortization |
|
|
(5.69) |
|
|
(3.32) |
|
Asset Retirement Obligations Accretion |
|
|
(0.12) |
|
|
(0.08) |
|
Interest Income |
|
|
0.03 |
|
|
- |
|
Interest Expense |
|
|
(2.63) |
|
|
(1.11) |
|
Income before Income Taxes |
|
$ |
(4.51) |
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$ |
12.36 |
(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.
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.
Coal Operations
|
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|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
||||
|
|
|
2026 |
|
2025 |
||
|
|
|
(in thousands) |
||||
|
Coal Sales |
|
$ |
46,412 |
|
$ |
54,774 |
|
|
|
|
|
|
|
|
|
Fuel |
|
$ |
(528) |
|
$ |
(556) |
|
Other Operating and Maintenance Costs |
|
|
(20,273) |
|
|
(23,854) |
|
Utilities |
|
|
(3,199) |
|
|
(3,476) |
|
Labor |
|
|
(19,259) |
|
|
(18,886) |
|
General and Administrative |
|
|
(2,211) |
|
|
(2,313) |
|
Segment EBITDA |
|
|
942 |
|
|
5,689 |
|
Other Operating Revenue |
|
|
1,140 |
|
|
1,261 |
|
Depreciation, Depletion and Amortization |
|
|
(4,204) |
|
|
(9,797) |
|
ARO Accretion |
|
|
(277) |
|
|
(307) |
|
Exploration Costs |
|
|
(84) |
|
|
(21) |
|
Gain on Disposal or Abandonment of Assets, Net |
|
|
201 |
|
|
21 |
|
Interest Income |
|
|
111 |
|
|
63 |
|
Interest Expense |
|
|
(808) |
|
|
(1,991) |
|
Income (Loss) before Income Taxes |
|
$ |
(2,979) |
|
$ |
(5,082) |
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
||||
|
|
|
2026 |
|
2025 |
||
|
|
|
(per ton) |
||||
|
Tons Sold (in thousands) |
|
|
854 |
|
1,071 |
|
|
|
|
|
|
|
|
|
|
Coal Sales |
|
$ |
54.35 |
|
$ |
51.14 |
|
|
|
|
|
|
|
|
|
Fuel |
|
$ |
(0.62) |
|
$ |
(0.52) |
|
Other Operating and Maintenance Costs |
|
|
(23.74) |
|
|
(22.27) |
|
Utilities |
|
|
(3.75) |
|
|
(3.25) |
|
Labor |
|
|
(22.55) |
|
|
(17.63) |
|
General and Administrative |
|
|
(2.59) |
|
|
(2.16) |
|
Segment EBITDA |
|
|
1.10 |
|
|
5.31 |
|
Other Operating Revenue |
|
|
1.33 |
|
|
1.18 |
|
Depreciation, Depletion and Amortization |
|
|
(4.92) |
|
|
(9.15) |
|
ARO Accretion |
|
|
(0.32) |
|
|
(0.29) |
|
Exploration Costs |
|
|
(0.10) |
|
|
(0.02) |
|
Gain on Disposal or Abandonment of Assets, Net |
|
|
0.24 |
|
|
0.02 |
|
Interest income |
|
|
0.13 |
|
|
0.06 |
|
Interest expense |
|
|
(0.95) |
|
|
(1.86) |
|
Income (Loss) before Income Taxes |
|
$ |
(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.
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 |
|
854 |
|
4,094 |
|||||
|
Wash plant recovery in % |
|
66 |
% |
64 |
% |
57 |
% |
59 |
% |
|
|||||
|
Capex (Coal Operations) |
|
$ |
5,793 |
|
$ |
6,873 |
|
$ |
6,449 |
|
$ |
3,792 |
|
$ |
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Mines |
|
2nd 2024 |
|
3rd 2024 |
|
4th 2024 |
|
1st 2025 |
|
T4Qs |
|||||
|
Tons produced |
|
889 |
|
873 |
|
971 |
|
1,020 |
|
3,753 |
|||||
|
Tons sold |
|
849 |
|
926 |
|
875 |
|
1,071 |
|
3,721 |
|||||
|
Wash plant recovery in % |
|
59 |
% |
60 |
% |
62 |
% |
64 |
% |
|
|||||
|
Capex (Coal Operations) |
|
$ |
7,560 |
|
$ |
6,810 |
|
$ |
11,079 |
|
$ |
6,244 |
|
$ |
31,693 |
|
Capex per ton sold (Coal Operations) |
|
$ |
8.90 |
|
$ |
7.35 |
|
$ |
12.66 |
|
$ |
5.83 |
|
$ |
8.52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average cost per ton sold⁽ⁱ⁾ |
|
$ |
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2nd 2025 |
|
3rd 2025 |
|
4th 2025 |
|
1st 2026 |
||||
|
Basic |
|
$ |
0.19 |
|
$ |
0.56 |
|
$ |
(0.01) |
|
$ |
(0.20) |
|
Diluted |
|
$ |
0.19 |
|
$ |
0.55 |
|
$ |
(0.01) |
|
$ |
(0.20) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2nd 2024 |
|
3rd 2024 |
|
4th 2024 |
|
1st 2025 |
||||
|
Basic |
|
$ |
(0.27) |
|
$ |
0.04 |
|
$ |
(5.06) |
|
$ |
0.23 |
|
Diluted |
|
$ |
(0.27) |
|
$ |
0.04 |
|
$ |
(5.06) |
|
$ |
0.23 |
INCOME TAXES
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.
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.
Cash and cash equivalents
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.
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.
Consolidated Statement of Cash Flows Summary.
The first quarter of 2026 and 2025 unaudited condensed consolidated statements of cash flows are summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
||||
|
|
|
2026 |
|
2025 |
|
Change |
|||
|
Net cash provided by operating activities |
|
$ |
20,496 |
|
$ |
38,419 |
|
$ |
(17,923) |
|
Net cash used in investing activities |
|
|
(7,480) |
|
|
(11,672) |
|
|
4,192 |
|
Net cash (used in) provided by financing activities |
|
|
14,975 |
|
|
(22,693) |
|
|
37,668 |
|
Increase in cash, cash equivalents, and restricted cash |
|
$ |
27,991 |
|
$ |
4,054 |
|
$ |
23,937 |
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
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.
Hallador Energy Company published this content on May 06, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on May 06, 2026 at 21:22 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]