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DATE

Thursday, May 7, 2026 at 11 a.m. ET

CALL PARTICIPANTS

  • President — Michael Hollis
  • Chief Executive Officer — Steven Bowland
  • Chief Operating Officer — Ryan Hightower

TAKEAWAYS

  • Production volume -- Average daily production reached approximately 46,000 BOE, about 7.5% above the midpoint of guidance.
  • Oil production growth -- Oil production grew 10% sequentially from the prior quarter, with gains attributed to both new wells and optimized base production.
  • Lease operating expense -- Lease operating expense per BOE was more than 17% below guided range and 22% below Q4 levels, with absolute costs down $7.4 million quarter over quarter.
  • Capital spending -- Capital expenditures represented 29% of the full-year budget, closely aligning with management's planned 60% first-half spend.
  • Development pace -- Drilling and turn-in-line activity for the first quarter comprised about one-third of the 2026 plan, with 18 wells in progress at quarter-end.
  • Capital efficiency -- "Net oil produced per dollar of capital invested" improved by over 60%, increasing from roughly 21,500 barrels to approximately 35,400 barrels per million dollars capitalized.
  • Base optimization projects -- Sixteen workover projects raised production from 1,600 to 2,600 barrels of oil per day, a 63% per-well increase on average.
  • Free cash flow -- Excluding working capital, free cash flow exceeded $21 million, up from negative $42 million in the prior quarter, reflecting less than one month of elevated oil prices.
  • Hedging program -- Approximately 40% of production exposure is to spot oil prices, with a hedge floor in the mid-$60 per barrel range for downside protection.
  • ATM program -- An at-the-market program was initiated, permitting issuance of up to $150 million in common stock, with proceeds intended for debt reduction and liquidity enhancement.
  • Water management infrastructure -- Saltwater disposal (SWD) capacity exceeds 400,000 barrels per day, currently 45%-50% utilized, supporting scalability and operational cost containment.
  • Inventory adjustment -- Inventory in a specific Wolfcamp A area was reduced by 18 planned wells due to water encroachment, with no future drilling planned there; three producing wells in the area remain under optimization.
  • 2026 production outlook -- Management expects a flat production profile for the remainder of the year, with volumes currently tracking at or above the upper end of guidance.
  • 2027 preliminary plans -- Activity and capital spending are anticipated to mirror 2026, with an expected exit inventory of nine to ten DUCs (drilled but uncompleted wells).
  • Mark-to-market hedge loss -- First-quarter derivatives loss totaled $157.4 million ($17.4 million realized, $140 million unrealized), which may decrease if oil prices fall later in the year.

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RISKS

  • Michael Hollis cited, "High Peak is not going to drill another well in that little red box," reflecting loss of future drilling opportunities in an area affected by water encroachment and a reduction of 18 wells from inventory.
  • Steven Bowland acknowledged, "total derivatives loss in the first quarter on paper was about 15.055 billion dollars. Only 17.4 of that was actual cash loss. The rest of it, roughly 140 million, was a mark-to-market loss," indicating sensitivity to continued commodity price volatility and its potential impact on earnings.

SUMMARY

HighPeak Energy (HPK 9.55%) produced operational and cost efficiencies beyond targets, raising output and lowering unit operating expenses while deploying less than 30% of its annual capital budget. Management outlined a disciplined, flat production strategy with capital weighted toward the first half of the year and indicated no inclination to accelerate activity despite recent oil price strength. Implementation of optimization workovers increased per-well yields, while foundational infrastructure investments, particularly in water handling, enabled further cost control. The company initiated an at-the-market equity program, providing financial flexibility to strengthen the balance sheet. Aggressive capital efficiency improvements and a favorable hedge profile position HighPeak for incremental free cash flow if commodity prices remain firm.

  • Management projects consistent production with current volumes trending above the guided range, supported by both new and optimized wells.
  • The move to a maintenance-mode development approach is explicit, targeting maximum free cash flow instead of production growth.
  • Free cash flow priorities are clear—debt reduction and liquidity improvement—with no immediate intent to issue equity absent market opportunities.
  • Large mark-to-market derivative losses reflect ongoing earnings sensitivity to oil price changes, underscoring the importance of the hedge program for cash flow stability.
  • Infrastructure capacity provides both operational resilience and an ability to leverage existing assets as the business scales or encounters cyclical commodity conditions.

INDUSTRY GLOSSARY

  • BOE: Barrel of Oil Equivalent; a standardized unit combining oil, natural gas, and NGLs for reporting production volume.
  • LOE: Lease Operating Expense; direct operating cost per barrel of oil equivalent produced.
  • ATM program: At-the-Market equity offering; a mechanism allowing a company to sell shares incrementally at current market prices.
  • DUC: Drilled but Uncompleted well; a well that has been drilled but not yet hydraulically fractured and placed into production.
  • SWD: Saltwater Disposal; facilities or wells used to inject produced water safely underground.

Full Conference Call Transcript

Michael Hollis: Thank you, Steve. Good morning, everyone, and thank you for joining us. We appreciate you taking the time to be with us today. I'm gonna spend a few minutes walking through our first quarter results, how we're positioned today, and how we're thinking about the rest of 2026. And I'll tell you right up front, the business is doing exactly what we said it would do. We are executing, we're staying disciplined, and we're building a stronger company quarter by quarter. Let's start with the first quarter. We're off to a very strong start this year, and I'm proud of the way our team has performed across the board. We outperformed expectations on every major operational metric.

Production averaged approximately 46,000 BOEs per day, which came in about seven and a half percent above the midpoint of our guidance range, which includes the effects of winter storm firm, and with quarter-to-date production coming in as strong as or stronger than Q1 production. Now oil production specifically was up 10% quarter over quarter, which is a meaningful step up and speaks to the quality of both our new wells and our base production. And that's important because it wasn't driven by just one thing. It was a balanced success. We saw strong performance from the new wells we brought on during the quarter, and at the same time, we continue to optimize and improve our base production.

That combination is what drives consistency in the business. It's a direct result of the operational work our team has been focused on over the last several quarters, dialing in execution, tightening processes, and getting better in every aspect of the business. Now let's talk about cost, because this is where we really separated ourselves this quarter. Our operations team delivered exceptional cost performance. Lease operating expense per BOE came in more than 17% below our guided range and roughly 22% below the fourth quarter levels. That's a material improvement in a very short period of time. And just as important, it wasn't just a per-unit story.

On an absolute dollar basis, our operating cost declined by approximately 7.4 million quarter over quarter. So we spent meaningfully less money while producing more barrels. That's exactly what operational efficiency should look like. Now what drove that? Three primary areas. First, continued optimization of our chemical program, making sure we're using the right treatments in the right places at the right cost. Second, more efficient use of fuel gas. Given the current dislocation between Waha pricing and Henry Hub, we're not making money on our gas at the moment, so we're putting it to work in our own operations wherever we can. That's a practical economic decision and is paying off. And third, continued electrification across our field operations.

That's improving reliability, lowering cost, and positioning us well for the long term. Now put it all together. This is a structurally more efficient business than it was just a few quarters ago. Turning to our development program, we are exactly where we need to be. First quarter drilling and turn-in-line activity represents roughly one-third of our planned 2026 program. Capital spending came in right in line with expectations at about 29% of our full year budget. We exited the quarter with 18 wells in progress, and that puts us in a strong position to execute the remainder of the year.

Now as a reminder, we guided to deploying roughly 60% of our capital in the first half of the year, and we remain firmly on track with that plan. Execution is steady, predictable, and controlled. Now let's step back and talk about the bigger picture: capital discipline and efficiency, because that's really the core of our strategy. As you know, we made a deliberate shift heading into 2026. We reduced our capital program by roughly 50% compared to last year and we moved into what we are calling maintenance mode development strategy. And the goal is to hold production roughly flat while maximizing free cash flow. And the early results are very encouraging.

One key metric we track is net oil produced per dollar of capital invested. Quarter over quarter, that metric improved by more than 60%, moving from about 21,500 barrels per million dollars of capital spent to approximately 35,400 barrels per million. That's a significant step change in efficiency. And, again, it's coming from both sides of the business: strong well performance on new capital and meaningful gains on the base asset. Now let me spend a minute on that base optimization work, because it's an important part of the story. During the quarter, we executed 16 targeted workover projects. These projects increased production from roughly 1,600 barrels of oil per day to about 2,600 barrels of oil per day.

That's an add of about a thousand barrels of oil per day, and, importantly, an increase of 63% per well on average for those 16 wells, with relatively low capital intensity. That's exactly the type of work we want to be doing, especially in this current commodity price environment, where every incremental barrel we produce receives elevated spot price. These projects leverage infrastructure we already own, target opportunities we understand well, and they generate extremely high-margin barrels. This is what disciplined capital allocation looks like in practice. Now let's talk about the broader environment and how we're thinking about it here at High Peak. There's obviously a lot going on in the world right now.

We've seen significant volatility in commodity prices driven largely by geopolitical developments in the Middle East. Near-term oil prices have moved meaningfully higher, but when we look at the market, and more importantly, when we make decisions, we focus on the back end of the curve. And what we've seen there is a much more modest move, roughly a $10 to $12 increase from around $60 a barrel at the beginning of the year to the low seventies per barrel currently. Now that's constructive, but it's not something that fundamentally changes our strategy. We are not going to chase short-term price signals. We're not going to accelerate activity just because spot pricing has moved.

We are going to stay disciplined and develop this asset at the right pace, and that's one that reflects sustainable pricing, capital efficiency, and long-term value creation. Now, with that said, this geopolitical situation, if it persists, we do believe there will be increasing pressure on the back end of the curve over time. And if that happens, it creates a meaningful long-term opportunity for High Peak. More sustained pricing strength means higher incremental free cash flow for years to come. And that's where real value gets created. And importantly, we are positioned to benefit from that environment.

We currently have approximately 40% average exposure to spot oil prices based on the midpoint of our production guided range and our current hedge book. Please know that current production is well above this level and gives even more exposure. That gives us meaningful upside to stronger pricing, and at the same time, we've protected the downside. We've established a hedge floor in the mid-$60 per barrel range that provides a reliable base level of cash flow to fund our development program and service our debt. So we've got both upside torque and downside protection. And you saw that show up in the first quarter. Excluding changes in working capital, we generated over 21 million of free cash flow.

That's up from a negative 42 million last quarter. And that only reflects less than one month of elevated oil prices. If prices remain higher for longer, that free cash flow number moves up materially as we move through the year and accelerates the time frame needed to strengthen our balance sheet. Again, our priority for that free cash flow is very clear. We are going to strengthen the balance sheet. One additional item to touch on as we talk about strengthening the balance sheet: we recently put an at-the-market, or ATM, program in place. This gives us the ability to issue up to 150 million of common stock.

Now just to be clear, there is no requirement for us to issue a single share under this program. This is about flexibility. It's a tool that allows us to be opportunistic if we see dislocations in the market. If we do choose to access the ATM, the use of proceeds is very straightforward. It's about reducing debt, increasing liquidity, and continuing to strengthen the balance sheet. Now let me close with our focus for the year. Look, nothing's changed, and that's by design. Our priorities are clear. First, strengthen the balance sheet through sustained free cash flow generation, debt reduction, and/or increasing liquidity.

Second, preserve high-quality inventory by developing our inventory at a disciplined pace and continuing to optimize both new wells and our base production. Third, improve corporate efficiency, focusing on returns, not volumes, and ultimately create long-term equity value and maximize net asset value. We are allocating capital where it drives the highest returns, and we are building a more durable, more resilient business that is built to thrive across commodity cycles. Now stronger commodity prices are helpful, no question. But disciplined execution is what creates long-term value. And that's exactly what High Peak is delivering. With my comments now complete, operator, please open the call up for questions.

Operator: Operator. I am so sorry for the technical—I'm sorry. We had some technical difficulties there for a moment. We will conduct the question and answer session now. As a reminder, to ask a question, you will need to press 11 on your telephone and wait for your name to be announced. To withdraw your question, please press 11 again. Our first question today comes from Jeff Roe with Water Tower Research. Your line is open.

Analyst: Good morning. Mike, given where you are with production and 60% of estimated ’26 capital being spent in the first half of the year, can you share some color on production levels progression in the back half of the year? And with the inventory of DUCs that you might exit ’26, any early or preliminary color on 2027?

Michael Hollis: No, Jeff. Great question. And as we laid out in our guidance last quarter, we were planning to spend roughly 60% of that budget in the first half of the year, and as we've shown here in Q1, we were right along that. We did about 33% of the activity for the year and came in a little under 30% of the capital spent for the year. So as you look through 2026, the activity in Q2 will be very similar to what we had in Q1. From a production standpoint, yes, we're running hot to our guide today, and up through quarter to date even.

And as you look through the latter half of the year, the additional work that we do in the first half—that is, the wells that are going to be producing in the second half of the year. So I think what you'll see throughout 2026 is more of a flat production profile that looks very similar to what we've done to date this year. And, again, yes, it's a little hot to our guided range—above the top end of the guided range.

And we hope between base optimization projects that we're working on and the great performance we've had from our new wells—and we're drilling very similar wells throughout the entire year, and that's what's going to be coming online—then we will be in the upper portion of that production range that we guided to originally. But for the CapEx spend, the guided range is still very applicable, and I think we demonstrated that in the first quarter.

Analyst: If you think about 2027, Mike, would you plan, from an activity standpoint, another year where it's weighted toward the first half of the year to, as you said, support getting the full benefit of production in the year the wells are being drilled, or as much of it as possible?

Michael Hollis: I don't know that we're detailed enough to mica break, as I like to call it, from West Texas slang. But I think if you look into 2027, I would assume a very, very similar program to what we had in 2026. And there was one question I did not answer, which was how many DUCs we would exit the year at. We will exit with roughly nine to ten DUCs in 2026 going into ’27. So we would be set up very similarly to do the exact program that we have in ’26 and ’27.

So, again, if you're looking at kind of a CapEx spend in ’27, I think what we have this year, the midpoint of about 270 million, is where you need to be coalescing for modeling purposes.

Analyst: On your workover efforts, are you doing anything differently to try to identify wells that need some attention and therefore justify the expense of going in and spending capital that turns into LOE expense but results in the increased production that you highlighted on slide seven?

Michael Hollis: No, that's a great question. And Jeff, we've got upwards of getting now close to 400 wells that are producing. So as we go through all of our inventory of producing wells, we do have a list of wells that we think would benefit from this type of intervention more than others. However, if a well is producing fine—everything's good—you probably wouldn't go take that well off production and go do this type of intervention. Typically, what we are looking for—and, again, we don't wanna do too many at one time. We're pretty early in this process.

So what we've done to date are wells that we were going to go touch and do work on for some reason or another, and they met the requirements and looked like a good candidate—those are the ones that we went and did. And I think that's how you can kind of assume we will do for this year, maybe even next year. We need more time to watch the production increase that we have from these interventions and how that plays out over kind of a year, two-year time frame to really understand that before we would wanna go and attack a well that's currently producing.

And, you know, these are well interventions that we were going to have to do something—think of the, I like to call it a mini stimulation on the well—things like surfactants, acid, more or less cleaning the wellbore out and reducing damage to the formation that happened over time. And we're seeing really good results. I think as you look forward in the two, three years from now, basin-wide, this is going to become one of the new knobs that we can turn in our industry to hopefully be able to extract a higher ultimate recovery out of the wells in the basin.

You know, you're hearing this kind of thematically across a lot of the other companies' releases that they are kind of experimenting with some of these things too. So I think this is something that's here to stay and will increase the total recovery of this area.

Analyst: Ryan or Mike, we had big working capital swings in the first quarter, which impacted free cash flow, as you noted in your remarks. Can you talk about how much of that activity was isolated to one-quarter events and how we should think about that as you move forward through 2026?

Steven Bowland: Yeah. Great question, Jeff. If you recall, for the bulk of the fourth quarter, we ran two rigs, and we also had a couple of really large final frac jobs. So we did have a negative working capital swing of about 35,000,000 in Q1. A lot of that is just that capital from the additional rig and a couple of those final frac jobs kind of working its way through the system. All that's behind us now. So on a go-forward basis, it's more steady state. So I wouldn't expect those large working capital swings on a go-forward basis throughout the rest of the year.

Analyst: And just lastly, Ryan or Steve, High Peak had a big unrealized mark-to-market hedge gain in the first quarter, which obviously impacted reported earnings. Can you talk about how that gain would be treated as you move forward in 2026 in a potentially lower oil price environment than what ended the first quarter?

Steven Bowland: Yes, absolutely, Jeff. And I think you're referring to a large hedge loss in the first quarter. So the way to think about it, total derivatives loss in the first quarter on paper was about 15.055 billion dollars. Only 17.4 of that was actual cash loss. The rest of it, roughly 140 million, was a mark-to-market loss that was done as of March 31. So the way to think about that: if prices kind of pull back to lower levels throughout the rest of the year, that mark-to-market loss is going to shrink, and any potential cash hedge loss would shrink as well as we progress throughout the year.

Michael Hollis: Thank you. Thank you.

Operator: Thank you very much. Our next question is from Nicholas Pope with Roth Capital. Your line is open.

Analyst: Hey. Good morning, guys. Curious to dig a little bit more on the workovers. And I know you have this slide kinda talking about the benefits of that. It looks like the workover expense for the quarter was actually pretty low relative to what the run rate was in 2025. And so just trying to understand what the activity expectation is going forward. I mean, a lot of wells, obviously, that you're looking at to potentially augment with improved productivity with these workovers, but we're kinda looking at this expense line item. It didn't seem like you had as much work, and it was certainly helpful for the LOE line item for the quarter.

Just maybe trying to understand how that splits out—how much is going into capital expenses, how much is in this workover expense, and what that should be going forward.

Michael Hollis: No. Great question, Nick. So let me step back to last year. And to kinda answer the question as to why overall LOE is down—you know, LOE is kinda two buckets, right? It's your chemical and day-to-day everyday LOE, and then it's your workover expense. And think workover expense is repairing something on a well and just getting it back to the same kind of state that it was. That's the workover expense.

If you look back into last year, kind of the latter 2025, our workover expense started marching up throughout that year because we went and did a lot of those, getting the base production and the wells in tip-top shape, and we spent, call it, a dollar-ish or a little bit more per BOE doing that in 2025. We only have so many wells, and there's always going to be some workover expense. Make sure you don't read through that it's going to zero. But I think a reasonable run rate for workover expense—probably somewhere in the 75¢ to a dollar range—is extremely conservative. Obviously, we are much lower than that in Q1.

Now to answer your other question about the type of interventions: again, we touch a lot of wells all the time. Some are designated as expense work—basically getting the well back to its original state. Some are considered capital workovers where you're adding reserves and actually changing the value of the well after the fact. So to that, I would say with all the work we did throughout the quarter, some of these were capital workovers and are in our capital spend for the quarter, and I think that screened very well for the amount of work we did on our D&C budget.

The read-through there is we're shaping cost where we can on our traditional D&C budget enough that we're going to be able to slice some of these capital workovers in within the budget we currently have. And on the expense side, again, we wanted to be very conservative with our early guide range. That's why you saw a fairly sizable workover program, because we wanted to say, hey, if we had to continue what we did in ’25, this gives us plenty of money in the budget to do it. But I think you're looking at it exactly right.

It's not like we just moved a lot of costs from the expense bucket to the capital bucket, or you would have seen it show up there. Overall total cost is coming down.

Analyst: One other piece of this, and I don't know if it's connected or not. It sounds like it might have been the second half of last year, as you stepped out further to the east, you had some of the issues with water encroachment in some of the newer extensional wells. Where does that stand? Has that area just been written off at this point? And are those wells just not really part of the existing production or any plan going forward?

Michael Hollis: Great question, Nick. You know, a quarter or so ago, we had a slide that showed a red box right exactly where you're talking about. And, yes, we encountered some extraneous water production in that area. You know, we kinda talked about the impact it had on our inventory. So the only zone we carry inventory in that little red box was Wolfcamp A. And the quick answer is no, High Peak is not going to drill another well in that little red box. And that equated to about 18 wells coming out of our inventory. Now the existing wells that we do have there—we've got three of those wells producing today.

We've done some interventions on those wells to reduce the amount of water coming in, so they are very economic. They're just lower production because you're only producing from, call it, 4,000 feet of actual producing rock out of those wells. From an economic standpoint for a new well, no, we would not drill another one. But we will optimize the wells that we do have in that area. But, absolutely, that had an effect with production kind of in the second half of 2025. And, again, all of that kind of rolls through on a BOE basis for your LOE per BOE cost in the second half of the year as well.

Analyst: And I think I've talked to you about this before, but total High Peak water handling and disposal capacity relative to what y'all are seeing in terms of water volumes currently?

Ryan Hightower: Great question. And, again, we constantly highlight the infrastructure that High Peak has put in place over the last five-plus years. And to your question there on the water system, if you look back a couple years, we were running six rigs, three frac crews, and looking to build to 75,000 to 100,000 barrels of oil a day. Now with that, you need to be able to handle 400,000 barrels of water per day. So we put in very large pipes, very large pumps, several SWDs. So our SWD capacity is a little over 400,000 barrels. Big pipelines that are 24 inches in diameter—we can move around 400,000 barrels a day.

And, of course, we recycle almost 95% of what we use on the stimulation side. But just to give you an idea of where we sit today: we're producing roughly, on the gross basis of oil that we produced, pretty close to 45,000 to 47,000 barrels gross of oil. So with that kind of four to one, we're a little over 200, call it 210 to 220,000 barrels of water a day being produced across High Peak. Some of that—being a little bit more than four times—is because you have some flowback from the new frac wells. But we're about 45% to 50% utilized of capacity that High Peak has. We take very little third-party water into our system.

It's available. So for folks near and around us, we do have plenty of capacity for disposal. But the infrastructure was built for life of field, and that stretches across our oil, gas, electrical, recycle capability. All of that's built in place. And I think you're seeing that on our LOE cost numbers. And then same thing on our CapEx numbers—as we have built all of our large central tank batteries, you're starting to see the cost per well go way down. Because today, when we drill a new well, all we have to do is add some metering equipment to tie it into an existing battery that's already there.

So both sides of the equation are what we've attacked, and we've been able to bring cost down across the board.

Analyst: Got it. That is all very helpful. Mike, I appreciate the time. Guys, I appreciate the time.

Michael Hollis: Hey. Go ahead. Thanks, Nick.

Operator: Thank you very much. This does conclude our question and answer session. We thank you very much for your participation in today's conference. You may now disconnect.