Hallador Energy Company

Good afternoon. Thank you for attending Halador Energy's fourth quarter and full year 2024 earnings conference call. At this time, all participants are in listen-only mode. Later, we will conduct a question and answer session, and instructions will follow at that time. As a reminder, this call may be recorded. I'd now like to turn the conference over to Sean Mansouri, the company's investor relations advisor with Elevate IR. Please go ahead, Sean.

Thank you, and good afternoon, everyone. We appreciate you joining us to discuss our fourth quarter and full year 2024 results. With me today are President and CEO, Brent Vilswind, and CFO, Margie Hargrave. This afternoon, we released our fourth quarter and full year 2024 financial and operating results in a press release that is now on the Halidor Investor Relations website. Today, we will discuss those results as well as our perspective on current market conditions and our outlook. Following prepared remarks, we will open the call to answer your questions. Before we begin, a reminder that some of our remarks today may include forward-looking statements subject to a variety of risks, uncertainties, and assumptions contained in our filings from time to time with the SEC and are also reflected in today's press release. While these forward-looking statements are based on information currently available to us, if one or more of these risks or uncertainties materialize, or if our underlying assumptions prove incorrect, actual results may vary materially from those we projected or expected. In providing these remarks, Halidor has no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise, unless required by law to do so. We plan on filing our Form 10-K shortly. And with the preliminaries out of the way, I'll turn the call over to President and CEO, Brent Zeldman.

Thanks, Sean. Thank you, everyone, for joining us this afternoon. 2024 was a transformative year for Halidor as we evolved from our traditional position as a co-producer to vertically integrated power producer or IPP, while also advancing our products and services up the energy value chain. This deliberate shift aligns with broader market trends and our beliefs in the superior economics of the IPP model, which we feel is essential to unlocking long-term value for our shareholders. In October of 24, We reached an important milestone in our transformation by signing a non-binding term sheet with a leading global data center developer to support their power and accredited capacity needs for over a decade. We followed up the non-binding term sheet with an exclusivity agreement that runs from January through early June of 2025 and provides us with comfort based on our partner's willingness to pay up to $5 million throughout the exclusivity period. These agreements, in combination with our partner's additional large-scale financial commitments to third-party stakeholders necessary for the transaction, highlight the meaningful progress that we feel we've made towards finalizing a definitive agreement within our exclusivity period. While navigating these complex transactions requires coordination across multiple stakeholders, we remain encouraged by the commitment of our partners and believe this strategic partnership will drive long-term value for our shareholders. We continue to witness the prevalent industry trend of retiring dispatchable generation, including coal, in favor of non-dispatchable resources, such as wind and solar. We believe this transition from dispatchable to non-dispatchable generation makes the attributes of our subsidiary, Halador Power, much more valuable due to the enhanced reliability that we provide versus non-dispatchable generators. However, we believe the retirement of coal-based generation and lower natural gas prices could reduce the demand for coal supply. potentially lowering the value of our Sunrise Coal subsidiary. In anticipation of these market dynamics and in connection with our active management of the cost structures within Sunrise Coal, we proactively reduced volumes and shed higher cost coal reserves, which lowered our operational cash costs in the fourth quarter. During the fourth quarter of 2024, we also completed our annual impairment analysis, which was based upon our current operating plans, market-driven pricing and cost trends. As part of that analysis, we determined the carrying amount of Sunrise's long-lived assets were not recoverable and recorded a non-cash long-lived asset impairment charge of 215.1 million in the fourth quarter of 2024. We believe this analysis underscores the necessity and foresight of our ongoing focus and transition to power generation. Howard Power's ability to generate up to 6 million megawatt hours annually at Merham continues to provide significant opportunities. The forward power price curves indicate that the margins earned on energy produced at Merham and the value of accredited capacity sales assigned to the plan continue to increase. We have seen strong indications for price improvements in 2025 and beyond, particularly in relation to data center development efforts in Indiana. It is unclear whether the forward pricing curve has yet factored in this fast-growing demand. We have historically focused on selling energy through bespoke bilateral agreements on a unit or plant contingent basis. However, during 2024, we sold a limited amount of power on a firm basis. While we continue to limit these types of firm sales to mitigate risk, as we wait for high price unit contingent contracts to take effect, we expect to strategically utilize them to smooth our exposure to the spot market. This approach enables us to capture some of the episodic cash generation, largely driven by demand from extreme weather and various other conditions that stress the power grid, while also lessening the negative pricing impacts during the period of mild weather and low natural gas prices. This also enables us to shift from the lower pricing related to our initial Merrim acquisition to traditional wholesale market pricing, where we currently are in some regard and will largely be starting in 2026, and ultimately to the enhanced pricing and margins associated with supporting data centers and other large load end users as we look beyond 2026 and into the next decade. Despite an ongoing surplus of natural gas and mild weather patterns moderating energy prices throughout 2024, we began to see favorable pricing trends towards the end of the fourth quarter and early 2025. Combined with progress in our data center negotiations, this reinforces our belief that Merrim's earnings potential will expand meaningfully if we execute on our strategic initiatives. Additionally, we continue to believe that the ability to store a commodity is inherently tied to the volatility of that commodity. Coal can be piled up for years, thus the volatility is low. Oil and natural gas face transportation and storage challenges, which increase price volatility. The limitations of storing viable energy coupled with non-dispatchable generation gaining market share in an environment where the sun does not always shine and the wind does not always blow, indicates that energy price volatility could increase over the next decade. We believe this uncertain volatility will sustain a premium in forward power prices, benefiting our long-term positions. We are also optimistic about how it will empower ability to capture higher prices and energy volumes in 2025 and beyond. In 2024, we generated 3.8 million megawatt hours at an average price of $48.62 per megawatt hour. However, for 2025, we have already contracted four and a quarter million megawatt hours at an average price of $37.24 per megawatt hour. And for 2026, we have secured 3.4 million megawatt hours of sales at an average price of $44.43 per megawatt hour. This reflects approximately 71% and 57% of our potential energy sales for 2025 and 2026 respectively. Beyond 2026, we are optimistic in our ability to sell energy at higher prices in support of data center development or to traditional wholesale customers as indicated by the higher forward curve. Beyond the transaction we are negotiating for Merum, we are actively evaluating additional strategic transactions that could expand our electric operations, increasing geographic reach and enhanced scale. While opportunities to acquire dispatchable generation assets are limited and complex, Haldor is uniquely positioned to repurpose underperforming or retiring assets to meet rising demand from data centers and onshore industrial customers. 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. Shifting to coal, we spent much of 2024 optimizing our Sunrise Coal Division to better align with our electric operation. Following the restructuring we initiated in the first quarter, we reduced headcount focused production on our most profitable reserves, and made infrastructure improvements to increase efficiency. These efforts successfully offset cost pressures while enhancing operational flexibility. In 2025, we expect our Mirren Power Plant to consume 2.3 million tons of coal from our Sunrise Coal subsidiary as well as third parties. We expect Sunrise to sell an additional 3 million tons of coal to third parties. Turning to our results for the fourth quarter, our wholly owned subsidiary, Haldor Power, generated 1.16 million megawatt hours in Q4, up 5% from the 1.1 million megawatts in the third quarter. While the energy environment remains volatile, During the quarter, we continued to see incremental improvements based on stronger pricing and higher dispatch rates. The gas inventory levels are returning towards the historic norms, resulting in higher natural gas prices than we have seen in recent quarters. Our gross margin for our power segment was $62.13 per megawatt hour sold, compared to $52.10 and 70 cents in the third quarter. Looking ahead, our focus remains on maximizing the value of our Miriam power plant, while actively pursuing opportunities to acquire additional dispatchable generators that can add durability, scale and geographic expansion to our electric operations. Additionally, we are forging strong relationship with counterparties seeking limited volume firm energy sales to secure favorable collateral terms and effectively manage our Ford's power sales and risk in 2025 and 2026, which we believe will enhance our financial flexibility in the short to medium term. We are excited about our continued transformation from a commodities-focused coal producer to an IPP, a strategy we believe will unlock expanding energy market margins, drive sustainable growth, and enhance cash flow generation for our shareholders. I will now hand the call over to our CFO, Margie Hargrave, to take you through our financial results. Margie?

Thank you, Brent, and good afternoon, everyone. Jumping right into the fourth quarter results. On a segment basis, electric sales for the fourth quarter were 69.7%, compared to 71.7 million for Q3 and 37.1 million in the prior year period, while coal sales were 23.4 million for the fourth quarter compared to 31.7 million in Q3 and 91.7 million in the prior year period. The expected year-over-year decline in coal sales was driven by our decision to reduce coal production. as part of the restructuring of our Sunrise Gold Division. On a consolidated basis, we generated $94.8 million in revenue for the fourth quarter, compared to $104.8 million in Q3 and $119.2 million in the prior year period. Net loss for the quarter was $215.8 million, compared to net income of $1.6 million in Q3, and net loss of $10.2 million in the prior year period. As Brent mentioned earlier, Q4 net loss was impacted by an approximate $215 million non-cash write-down associated with the value of our Sunrise Coal subsidiary. Operating cash flow for the fourth quarter increased to $38.9 million compared to operating cash used of $12.9 million in Q3 and $20.1 million in the prior year period, with the increase driven by a prepaid fiscal delivered power contract entered into during the fourth quarter. Adjusted EBITDA, a non-GAAP measure, which is reconciled in our earnings press release, issued earlier today was $6.2 million for Q4 compared to $9.6 million in Q3 and $2.1 million in the prior year period. We invested $13.8 million in capital expenditures during the fourth quarter, bringing total 2024 CapEx to $53.4 million. As we look to 2025, we expect CapEx to be approximately $66 million for the year, with roughly 20% related to federally mandated EPA ELG regulation. As of December 31, 2024, our forward energy and capacity sales position increased to 685.7 million compared to 616.9 million at the end of Q3 and 658.1 million as of December 31, 2023. When combined with our forward fuel sales, which were up more than 40% to 460.7 million compared to the end of Q3, Our total forward sales book as of December 31, 2024 was $1.6 billion compared to $1.4 billion at the end of Q3 and $1.5 billion as of December 31, 2023. In response to the more challenging environment for spot pricing, we continue to focus on strengthening our balance sheet. During the fourth quarter, we reduced our total bank debt to $44 million compared to $70 million at September 30, 2024, and $91.5 million outstanding at the end of last year. Additionally, we did not utilize our ATM program in the fourth quarter and have not utilized it since Q2 2024. Total liquidity at December 31, 2022. 2024 was $37,800,000 compared to $34.9 million at September 30, 2024, and $26.2 million at December 31, 2023. This concludes our prepared remarks, and we will now open it up for questions from those participating in the call. Operator, back to you.

To ask a question, please press star. 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. Please stand by while we compile the Q&A roster. Our first question comes from Nick Giles with B Reilly Securities, your line of social.

Thank you very much, Operator, and good evening, everyone. My first question, I wanted to ask about the regulatory and review process with the grid operator there was obviously some reporting around a submitted epr form so i was curious if you'd be able to offer any additional color around where this fits into ultimately reaching a definitive agreement thanks very much yeah hey nick uh well we we

Those were EPR filings are done by utilities at various locations across the state in their network, their respective networks. We certainly can't comment to all of those. We would probably highlight that there are several developers and hyperscalers out there asking to take electrons off the grid. for various developments. And, you know, we can't speak to which one we're particularly involved with at this time. We would say that we're thrilled that there are multiple access requests throughout the state because, you know, how it was in a position to sell to any and all of them should our should we not go forward with the particular development that we're with now? So I guess what I'm saying is we're not going to comment as to where our particular location of our particular project, but we are happy that there are multiple projects out there should our project not come to fruition. So Lots of good backup opportunities out there that we see on the radar as possibilities.

Understood. No, Brent, that's helpful. Maybe just to ask it in a different way, I mean, how should we think about remaining items between now and a definitive agreement? Is there – further due diligence required in the case of the developer? Or have we reached a stage in the process where it really could just be down to a series of approvals?

Yeah, you know, we're not going to be able to shed a ton of light. I apologize as to all the steps and where we're at in that process. You know, we During Q1, we signed an exclusivity agreement that runs through the first week of June. So I think that speaks to some degree to timing. And we were certainly glad to see the financial commitment from our counterparty with that agreement. But we've also seen further commitments with our counterparty with some of the other players in the process. So, look, we continue to be encouraged with the process that is made and the sincerity and commitment that we see from our counterparty. And we think we've made great progress. But a deal's not done until a deal is signed. And when that happens, we'll announce it. But we don't anticipate making a lot of announcements between today and the finish line, right? When it's signed, we'll have a deal and it'll be announced.

Understood. No, that's helpful. Maybe just as we think about the long-term agreement itself and Merrim, I believe there could be a requirement to co-fire with natural gas after the turn of the decade? So I was curious if you could speak to what's required at Merrim and maybe the capital intensity of any upgrade.

Yes. So the current law does state that all co-fire power plants must co-fire I think by 2032. That allows them to run through 2039 and beyond. And so we have begun studies to review that process and what that would take. We are fortunate that we have a natural gas line in close proximity to the plant, and we have hired a group to study that that has performed many co-firing of coal-fired power plants throughout the country, including a sister unit, Tamira. So we feel that, you know, the feasibility of such a study is – of such a process is very doable. And, you know, as we learn more about the cost and timing of that, we'll share that with the market, but we're not prepared to do that today.

Got it. Got it. That's helpful. Maybe one more if I could. I mean, Brent, you mentioned additional opportunities to acquire generating assets beyond Merrim. And so I was curious if you could add any color around geography, scale, and how we might think about acquisition costs. I know Merrim was more a transfer of ownership type of structure. And so should we think about similar opportunities where you might assume environmental liabilities and enter into some sort of forward agreement for energy. Thank you.

Yeah, so we certainly look at other opportunities, and they're located in lots of different states across the country, both on the coal side and on the gas side. We think there are additional opportunities out there. We have teams that actively look at these things. And we just have to take them on a case-by-case basis. You know, everyone has different economics, different challenges, different opportunities. And so it would be really hard for me to frame up, you know, hey, where is that going to be and what's that going to cost until we're further down further committed with those opportunities. All we are really trying to say is that we do actively have teams out there in discussions and we're encouraged by the market.

Fair enough. That's good to hear. Sorry, as far as terms of any agreement, should we think about energy delivery on a contingent basis similar to some of your other agreements, or would this be more of a long-term firm commitment? Just any additional color around structure?

Yeah, we typically sell the majority of our power on a unit contingent or plant contingent basis, and we would look to do that going forward in the future.

Got it. Got it. Well, Brent, congrats on all the progress so far. I appreciate all the color and continued best of luck.

Yeah, thank you. Thanks for your question.

Thank you. Our next question comes from Jeff Grant with Alliance Global Partners. Your line is open.

Afternoon, guys. Good afternoon. At the risk of beating a dead horse, I'll try to ask the data center question a little different way. What would you guys say are the major risks from your perspective with respect to locking something down over the next few months? Is there a way to kind of accept that on the outside at a high level?

Well, look, I mean, you know, we always want to try to under-promise and over-deliver. We feel that all the trends are moving our direction, right? I mean, we have increasing demand for power, both with data centers and onshoring of industry and EV adoption. And at the same – and if you want to access the grid, you have to – in MISO, you have to supply accredited capacity. And, you know, we have that. And you can't – you know, MISO and other grid operators have stripped the accredited capacity of from renewables, essentially, right? I mean, it used to be wind got 50% of nameplate, roughly, and solar got 50%, and now they get 15% and 5% effectively, and MISO has said they're going to cut that in half again in a handful of years. So you've got to get accredited capacity from something that has an on switch. That's coal, gas, nukes. and there are no nukes in the state of Indiana. So, you know, if you want to build something in MISO Zone 6, which is essentially the state of Indiana and the northern third of Kentucky, you know, you've got to get accredited capacity, and we think the only practical place to get that today is coal and gas generation. And so that's why we feel very encouraged about being able to eventually get something done. Timing is always a question mark. Again, I think we put an exclusivity period that ends in the first week of June, and that's the best signal we have for timing at this time.

Understood. I appreciate those details. That's helpful. And on the potential acquisition of other, you know, power assets, understanding, you know, you can't talk without the specific transaction, but just kind of curious to dig in, like, what does the buy box look like for you guys? Are there things that absolutely make sense a la coal versus things that maybe don't make sense? And also curious, you know, how important is control over fuel supply for, you know, whatever potential power generation asset? How important is that aspect for anything in the future relative to what you have now? Thanks.

So, you know, we've mentioned before that we have looked at both coal and gas generation. And we've mentioned that we've looked at other markets besides just MISO. And so, in the U.S. As far as coal supply to a coal plant, I think it's an advantage. It provides us with a lot of flexibility, but it isn't necessarily a have to have. It certainly is a nice to have because we do see times where the economic rent does make its way down to the fuel supply versus to the power generator. The nice thing about the setup we have now is we're we're vertically integrated. And so we feel we capture that economic rent regardless of which side of the ledger, the power side or the fuel side that it falls to. So we like our position. We certainly wouldn't be afraid of a plant in the future that we don't own the fuel supply to. But again, you just kind of have to evaluate all of these plants on a case-by-case basis. They all have you know, pros and cons, but we certainly think we understand how to unlock the value of the asset that we have, and we're looking to see if we can find situations that are similar to what we have today.

Great. That's really helpful, Brent. Appreciate the time.

Yes.

Thank you. Our next question comes from Jay Yoon. with Summit Ridge Capital Management. Your line is open.

Hey, guys. Thanks for taking my question. My first question is, sure, so in terms of pricing on a deal, have your views changed at all, or do you still expect a premium to the forward curves?

No, we still expect a premium to the forward curve. You know, nothing in that regard has We feel that the data center developers and hyperscalers, you know, continue to be very aggressive in the space. And, you know, we think that the addition of OpenAI and their Stargate project, you know, continues to add to that competition. I mean, essentially by them joining in the race, we've gone from four hyperscalers to five. And so that continues to put upward pressure on the economics, which is good for us.

Right. And that was my next question was, it seems like the environment has shifted in your favor the last few months. You mentioned there's more competition for, you know, demand for power, but it also seems like the co-location deals being held up by the regulators also helps you guys. So, Is there potentially upward pressure on pricing that you guys could realize?

Well, again, I mean, a deal is not done until it's signed. And, you know, but we are, like I said, we feel we've made good progress on our negotiations. And we're happy with the economics that we've negotiated to date. And, you know, at this point we're just trying to, you know, get that deal across the finish line. Gotcha.

Okay. And my last question, I know there's only so much you can talk about, but as we sit here today, do you feel better about getting a deal done than you did maybe two or three months ago? How do you feel about the progress you've made?

Yeah, I do think that we've made material steps. Again, the financial commitments, that we've seen not just to us but to other counterparties involved in the transaction is encouraging. And so from that perspective, I feel like our odds of success have continued to improve, particularly with the progress that we've made with our counterparties.

Right. And when you say financial commitment, do you mean CapEx for GPUs and things like that?

I don't want to get too far down into where the money is going, but yes, we've seen significant financial commitments from the parties involved. We think they wouldn't do that if they didn't feel that there was a high probability of success. Right. Understood.

Okay. Thanks a lot, guys. Appreciate it.

Thank you for your interest.

Thank you. Our next question comes from Nick Giles with eRiley Securities. Your line is open.

Thanks for taking my follow-up. I just wanted to go back to the CAPEX guidance you outlined earlier in the call. If you could maybe break that down between what's allocated to maintenance and what might be allocated to, you know, provisions like the ELG rule. I might have misheard that, but that's my first follow-up. Thank you.

Yeah, we actually did say what was allocated to the ELG rules, because we said about 20%, and so we have $66 million forecasted and budgeted for 2025, which is about, it's $14.8 million for the ELG rules.

Got it. Thanks, Margie. And Maybe just how should we think about, you know, so that would imply – would that imply upwards of $40 million for sustaining CapEx? Or how should we think about, you know, kind of a good sustaining CapEx figure to work with in the long term?

Oh, okay. I would – honestly, we normally have about $50 to $60 million. So if we took out the $15 million, we'd be at $51. We were at $53.4 million this year, 2024, so – I always think between 50 and 60 million.

Got it. That's very helpful. And maybe just along those lines, we're curious to get an updated view of how you're thinking about capacity payments in any long-term agreement. I think, you know, previous guidance was that capacity payments could cover fixed costs of the plant. So is that still a reasonable bogey?

Yes. Yeah, it's normally about 69. Okay.

And then I promise it will be my last one. Could you just speak to progress on the optimization of the operating footprint on the coal side? I mean, where do cash costs stand today? And then as we think about fuel needs at Merrim, does your internal supply cover that? full capacity, or would you likely need to purchase some third-party coal as well?

Yeah, so we made progress in the fourth quarter. Our cash costs were down into the low 40s, which was significantly better than being in the low 50s of where we were earlier in the year. As far as fuel supply goes, we do purchase fuel for the plant from other suppliers throughout the state. And, you know, it just kind of helps us from a diversity of supply. And, you know, so we buy from multiple vendors for the plant.

Got it. Guys, thanks again. I really appreciate all the color this evening.

Yeah, thank you, Nick.

Thank you. This concludes our question and answer session and today's conference call. Thank you for participating. You may now disconnect.