Hallador Energy Company (HNRG) | The Buildout — AI Infrastructure
The Verdict
Hallador Energy owns a coal-fired power plant in Indiana and the coal mine that feeds it. Merom, the plant, sells the two things large loads need before they can operate in MISO: accredited capacity, which an end user must hold before it can buy power, and wholesale energy. Management describes capacity as the gating factor for data centers, which is why capacity reprices ahead of energy — and Hallador has sold much of its capacity forward and is developing a gas peaker on the same site to sell more. The catch is that Merom's reliability drives the whole platform. When the plant runs poorly, electric sales, internal coal demand and mine productivity all fall together.
| Market Cap | — |
| Revenue (TTM) | $450M |
| Revenue Growth | +7.3% |
| EBITDA Margin (TTM) | 12.6% |
| Net Debt | $18M |
| Earnings Beats | 5 of 7 |
| P/E (TTM) | — |
| EV/EBITDA (TTM) | — |
What We Like
- Forward contracted revenue reached roughly $1.8B on a consolidated basis at 6/30/26, up from the $859.6M total in the 10-Q's 3/31/26 table; the segment-basis book including intercompany sales was about $2.4B.
- Two capacity agreements were struck at roughly 2x historical pricing: a 3-year deal executed in March 2026 with an investment-grade counterparty, and a 12-year deal signed May 2026 worth more than $1B from 2028 through 2040. Combined, they put roughly two-thirds of Merom's accredited capacity sold through 2040.
- The 10-Q's forward table shows contracted capacity pricing rising from $246 per MWd in 2026 to $264, $300 and $398 in 2027, 2028 and 2029 — signed evidence that capacity repricing has already happened, not a forecast.
- Turtle Creek Gas is a 460 MW simple-cycle peaker at the existing Merom site, budgeted below $800M (~$1,700/kW) with commercial operation targeted for 2H 2028. Hallador acquired 460 MW of Siemens turbines for $350M and says the equipment is in hand rather than queued.
- Post-quarter, Hallador closed a $600M senior secured term loan (up to $675M) on September 15, 2026, expected to fund the majority of Turtle Creek's project cost. Management's stated objective is little to no equity dilution.
What We’re Watching
- Merom reliability is the swing factor. Q2 2026 produced a $15.2M net loss after unplanned Unit 2 downtime landed during high power prices and forced replacement purchases at high cost. Management said it expects generation volumes to improve sequentially in Q3 2026, against a harder year-over-year comparison than a favorable Q3 2025.
- The 12-year capacity agreement needs Indiana Utility Regulatory Commission approval, which management anticipates in the second half of 2026. There was no IURC update on the Q2 2026 call, and pricing and volumes stay undisclosed until approval.
- Turtle Creek's final investment decision and generator interconnection agreement are targeted for September 2026, after MISO ERAS results on required system-upgrade costs. No EPC contractor has been named and the project is not yet at FID.
- Leverage rose from no bank debt at 3/31/26 to $45M at 6/30/26 and then to a $600M term loan in September 2026, while the operating core was consuming cash. Bank debt and liquidity both moved sharply in about six months.
The thesis is splitting in two. The structural side is strengthening: the contracted book roughly tripled in a quarter, two capacity deals were struck at about 2x historical pricing, and roughly two-thirds of Merom's accredited capacity is sold through 2040. The operating side is weakening: two consecutive net losses, negative Q2 2026 EBITDA, negative operating cash flow and rising debt. The two sides only reconcile if Merom runs reliably and the contracted capacity ramps as scheduled. The open question is whether the contracted cash flows arrive before the operating drag and the added leverage become the story — with the IURC ruling on the 12-year agreement as the nearest hard test.
Earnings Beat
Hallador reported Q2 2026 revenue of $101.5M, roughly flat against $102.9M a year earlier, with gross margin of 5.4% and EBITDA of negative $2.8M. A roughly 60-day planned outage at Merom plus unplanned Unit 2 downtime that landed during high market prices forced replacement power purchases at high cost. Net loss was $15.2M. Accredited capacity revenue rose 70% year over year to $18.6M, while the average delivered energy price fell to $41.69/MWh from $52.66.
| Metric | Q2 FY2026 | Q1 FY2026 | Q2 FY2025 | YoY |
|---|---|---|---|---|
| Revenue | $102M | $100M | $103M | −1.4% |
| Gross margin | 5.4% | -0.6% | 55.1% | -4970bps |
| EBITDA | −$3M | $4M | $17M | −116.1% |
| EPS | $-0.32 | $-0.20 | $0.19 | −269.2% |
| Accredited capacity revenue | $18.6M | $15.5M | n/a | +70% YoY |
| Total contracted revenue, consolidated | ~$1.8B | $859.6M | n/a | — |
Merom sits at the center of our vertically integrated platform. When the plant runs efficiently, it supports electric sales, creates consistent internal demand for coal, improves mine productivity at Sunrise, and enhances operating efficiency across the business. When performance at Merom falls below planned levels, those effects extend throughout the platform.— Brent Bilsland, Chairman and CEO, 2026-08-10
Management tone: Management's tone shifted between the two calls. On Q1 2026 they were defensive but forward-looking, framing a weak quarter as expected and leading with the new capacity agreement. On Q2 2026 they were operationally apologetic and strategically confident: they said plainly that the quarter's money and downtime went into Merom and that the results showed it. They named Turtle Creek Gas, cut its cost estimate a second time and pulled commercial operation forward to 2H 2028. They ruled out DOE financing for Turtle Creek directly. At the same time they withheld pricing and volumes on the 12-year capacity agreement, gave no IURC update, and dropped the dual-fuel initiative and M&A from the discussion entirely.
Management Guidance
For FY2026, management guided capital expenditures to remain consistent with 2025 levels, excluding Turtle Creek investments — a revision down from the prior call's expectation of a modest increase. They said they expect generation volumes to improve sequentially in the third quarter of 2026, while flagging a harder year-over-year comparison because Q3 2025 benefited from favorable power market conditions. They set a year-end 2026 goal to sell the remaining roughly one-third of Merom's accredited capacity on multi-year contracts and said some energy sales may occur in 2026 on a layered basis. DOE grant dollars for Merom's ELG compliance work are expected to be matched around Q4 2026 and continue into 2027 and 2028. The earlier full-year 2026 comparison to 2025 was not reissued.
Trajectory
Reported revenue fell to $100.2M in Q1 2026 from $117.8M a year earlier, then was roughly flat at $101.5M in Q2 2026 against $102.9M — but the mix is rotating. Electric sales are trading spot energy for contracted capacity: accredited capacity revenue rose 70% year over year to $18.6M in Q2 2026 while the average delivered energy price fell to $41.69/MWh from $52.66. Third-party coal revenue rose on a 9% price increase that more than offset a 2% decline in tons sold. Margins compressed with Merom's availability problems: gross margin was 5.4% in Q2 2026 and EBITDA was negative $2.8M. Underneath, the contracted book nearly tripled, from $571.2M of forward energy and capacity at 3/31/26 to about $1.6B at 6/30/26. The code-computed signals read decelerating revenue and compressing margins.
The Model
The model projects FY+1 revenue of $434.0M with EBITDA of $34M, a 7.8% margin, and FY+2 revenue of $426.6M with EBITDA of $77M, an 18.05% margin. Revenue is roughly flat across the two years; the change is in profitability, with EBITDA margin moving from 7.8% to 18.05%. FY+1 sits near the current run-rate of roughly $100M of quarterly revenue, so it anchors on Merom's operating performance and the capacity already contracted. The FY+2 range is wide for a reason: across the model's five runs, revenue spanned $380M to $459M, reflecting how much of the contracted capacity ramp and Turtle Creek output converts into reported revenue.
| Metric | FY2025 | Next FY (E) | Following FY (E) |
|---|---|---|---|
| Revenue | $469M | $434M | $427M |
| YoY Growth | — | −7.5% | −1.7% |
| EBITDA | $102M | $34M | $77M |
| EBITDA Margin | 21.8% | 7.8% | 18.1% |
Projections are the median of 4 independent model runs. The model’s revenue sits 2.6% below analyst consensus.
For FY2026, management guided capital expenditures to remain consistent with 2025 levels, excluding Turtle Creek investments — a revision down from the prior call's expectation of a modest increase. They said they expect generation volumes to improve sequentially in the third quarter of 2026, while flagging a harder year-over-year comparison because Q3 2025 benefited from favorable power market conditions. They set a year-end 2026 goal to sell the remaining roughly one-third of Merom's accredited capacity on multi-year contracts and said some energy sales may occur in 2026 on a layered basis. DOE grant dollars for Merom's ELG compliance work are expected to be matched around Q4 2026 and continue into 2027 and 2028. The earlier full-year 2026 comparison to 2025 was not reissued.
What Could Go Right — and Wrong
- The IURC approves the 12-year capacity agreement, firming more than $1B of contracted revenue from 2028 through 2040 and unlocking the pricing and volume disclosure that follows approval.
- Merom runs reliably and generation volumes improve sequentially in Q3 2026 as guided, cutting purchased-power costs and restoring electric margin.
- Hallador sells the remaining roughly one-third of Merom's accredited capacity on multi-year contracts, and some energy, before year-end 2026.
- Turtle Creek reaches final investment decision at or below $800M with interconnection and equipment on schedule, adding contracted capacity at a targeted 2H 2028 commercial operation.
- Energy prices rise and management monetizes the deliberately open energy position without committing new capital.
- The IURC rejects or delays the 12-year agreement, leaving the company's largest contract and its financing narrative unresolved past 2026.
- Merom reliability misses for a third quarter, producing another loss and more high-priced replacement power.
- Turtle Creek slips on cost, schedule or interconnection, straining a balance sheet that now carries a $600M term loan against a cash-consuming operating core.
- Coal demand softens. The third-party forward coal book already fell from $288.4M at 3/31/26 to $236.5M at 6/30/26, and a rail neighbor calls coal challenging in the second half of 2026.
- The financing mix shifts toward equity despite management's stated objective of little to no dilution.
Looking Ahead
The next twelve months turn on three gates: the IURC's ruling on the 12-year capacity agreement, anticipated in the second half of 2026; Turtle Creek's final investment decision and generator interconnection agreement, targeted for September 2026 with construction to follow; and year-end contracting, when management aims to sell the remaining one-third of Merom's accredited capacity and possibly some energy. Merom's reliability is the backdrop to all three, since it determines whether contracted capacity converts into cash. DOE matching dollars for Merom's ELG compliance work are expected around Q4 2026 and continuing into 2027 and 2028.
- September 2026Turtle Creek FID and GIA — Targeted final investment decision and interconnection agreement signing.
- September 2026Turbine shipment expected — 460 MW of Siemens turbines due to ship to the Merom site.
- 2H 2026IURC ruling on 12-year deal — Management says both parties are already bound; IURC approval is the last binding step.
- Q4 2026DOE grant matching dollars — Up to $27.2M award for Merom ELG compliance work.
- Year-end 2026Remaining capacity sales — Goal to sell the balance of Merom capacity on multi-year contracts.
- 2H 2028Turtle Creek commercial operation — Targeted COD for the 460 MW gas peaker.
Financials
Annual Summary
| Metric | FY2024 | FY2025 | TTM | YoY |
|---|---|---|---|---|
| Revenue | $401M | $469M | $450M | +16.9% |
| Gross Margin | 43.2% | 12.2% | -7.1% | 3,105bps |
| EBITDA | −$153M | $102M | $57M | +166.7% |
| EBITDA Margin | -38.2% | 21.8% | 12.6% | +5,999bps |
| Net Income | −$226M | $42M | −$1M | +118.5% |
| Free Cash Flow | $13M | $12M | −$50M | — |
| Net Cash | — | — | — | — |
Key Ratios (Trailing)
- P/E TTM—
- EV/EBITDA TTM—
- EV/Revenue TTM—
- Price/FCF TTM—
- Gross Margin (TTM)-7.1%
- EBITDA Margin (TTM)12.6%
- Net Margin (TTM)-0.2%
- ROIC5.7%
- FCF Conversion-88.9%
- SBC / Revenue1.0%
The Company
Hallador Energy is a vertically integrated independent power producer and fuel company with operations primarily in Indiana. It sells across three stages of the energy chain: accredited capacity, wholesale energy and Illinois Basin bituminous coal. The Electric Operations segment owns and operates the Merom Power Plant, a 1,080 MW coal-fired station in Sullivan County, Indiana, with two steam turbine generators that entered commercial operation in 1982 and 1983. The Coal Operations segment mines coal at the Oaktown Mining Complex, which sits about twenty miles from Merom so the plant and mine capture low-cost fuel on a delivered basis.
The company reports in two segments — Electric Operations through Hallador Power and Coal Operations through Sunrise, both wholly owned. Merom dispatches through its MISO interconnection. Accredited capacity is sold to utilities and other MISO participants mainly through power purchase agreements and bilateral transactions; energy is sold the same way plus on a spot basis in MISO day-ahead and real-time markets. Coal is typically sold free on board from the shipping point using rail networks and truck loading. Two functions are outsourced: CAMS manages operations, maintenance and asset management at Merom, and ACES acts as agent for wholesale power marketing and risk management. Hallador also holds 50% equity-method interests in Sunrise Energy and Oaktown Gas.
Business Segments
Competitive Landscape
On the coal side, Hallador competes with large producers such as Peabody Energy and Alliance Resource Partners and with other private producers; the 10-Q says that competition drives lower market prices. On the electric side, the 10-K and 10-Q say competitors are other power generators who bid into the MISO system. A machine-generated, spider-sourced wiring map also lists Constellation, Talen, Vistra and NRG as electric-side competitors, but it carries no documented quotes and should be read as directional. The neighbor read-through points to competition intensifying across nuclear, batteries, gas and hybrid solutions, with Hallador's niche the smaller, faster gas option at an existing site.
- Peabody Energy (BTU)Named in the 10-K as a large coal producer Hallador competes with in Coal Operations.
- Alliance Resource Partners (ARLP)Named in the 10-K alongside Peabody as a large coal producer; the 10-Q says such competition drives lower market prices.
- NRGListed as an electric-side competitor in a generated wiring map. The neighbor read-through compares NRG's Texas gas project at $2,700/kW and COD late 2029 to Turtle Creek's ~$1,700/kW and 2H 2028.
- Constellation (CEG)Listed as an electric-side competitor in a generated wiring map; the read-through notes long-dated nuclear PPAs averaging 18.5 years backed by investment-grade counterparties.
- Talen (TLN)Listed as an electric-side competitor in a generated wiring map; the read-through cites its hybrid existing-plus-new generation approach and an AWS PPA.
Supply Chain
Hallador sits between the fuel and the grid: its own Sunrise mine feeds its own Merom plant, which sells capacity and energy into MISO. No neighbor transcript mentions the company by name, so the read-through is triangulated from utilities, rail carriers and competitors.
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