HighPeak Energy Q1 2026 Earnings Call Transcript

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May 7, 2026

Key Takeaways

  • Positive Sentiment: Production averaged ~46,000 BOE/d (about 7.5% above the midpoint of guidance) with oil up ~10% quarter‑over‑quarter, leaving the company running above guidance into Q2.
  • Positive Sentiment: Operations delivered material cost improvement — LOE per BOE >17% below guidance and ~22% below Q4, with absolute operating costs down ~\$7.4 million quarter‑over‑quarter via chemical optimization, field gas reuse, and electrification.
  • Positive Sentiment: Management shifted to a maintenance‑mode development plan, cutting capital ~50% y/y and improving capital efficiency (net oil per \$1M capex up >60% to ~35.4k barrels), with ~29% of full‑year capex spent in Q1 and ~60% planned for H1.
  • Positive Sentiment: Base optimization and 16 targeted workovers added roughly 1,000 bbl/d (a ~63% avg increase for those wells) at low capital intensity, producing high‑margin incremental barrels.
  • Neutral Sentiment: Financially, the company generated >\$21M of free cash flow in Q1 (ex‑WC) vs a negative prior quarter, has ~40% spot oil exposure with a mid‑\$60s hedge floor, established a \$150M ATM for optional equity, and reported a \$155M derivatives mark‑to‑market loss (only \$17.4M cash impact).
AI Generated. May Contain Errors.
Earnings Conference Call
HighPeak Energy Q1 2026
00:00 / 00:00

There are 5 speakers on the call.

Speaker 3

Good day. Thank you for standing by. Welcome to HighPeak Energy 2026 first quarter earnings call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 11 on your telephone. You'll then hear an automated message advising your hand is raised. To withdraw your question, please press star 11 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Steven Tholen, Chief Financial Officer. Please go ahead.

Speaker 4

Thank you. Good morning, everyone, and welcome to HighPeak Energy's 1st quarter 2026 earnings call. Representing HighPeak today, our President and CEO, Michael Hollis, Executive Vice President, Ryan Hightower, Executive Vice President, Daniel Silver, Senior Vice President, Chris Mundy, and I am Steven Tholen, the Chief Financial Officer. During today's call, we may refer to our May investor presentation and press release, which can be found on HighPeak's website. Today's call participants may make certain forward-looking statements relating to the company's financial condition, results of operations, expectations, plans, goals, assumptions, and future performance. Please refer to the cautionary information regarding forward-looking statements and related risks in the company's SEC filings, including the fact that actual results may differ materially from our expectations due to a variety of reasons, many of which are beyond our control.

Speaker 4

We will also refer to certain non-GAAP financial measures on today's call, so please see the reconciliations in the earnings release and in our May investor presentation. I will now turn the call over to our President and CEO, Mike Hollis.

Speaker 1

Thank you, Steven Tholen. Good morning, everyone, and thank you for joining us. We appreciate you taking the time to be with us today. I'm going to 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. 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 measure.

Speaker 1

Production averaged approximately 46,000 BOEs per day, which came in about 7.5% above the midpoint of our guidance range, which includes the effects of Winter Storm Uri. With quarter-to-date production coming in as strong as or stronger than Q1 production. Now, oil production specifically was a 10% quarter-over-quarter, which is a meaningful step up and speaks to the quality of both our new wells and our base production. 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.

Speaker 1

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. 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. Just as important, it wasn't just a per unit story. On an absolute dollar basis, our operating costs declined by approximately $7.4 million quarter-over-quarter. We spent meaningfully less money while producing more barrels. That's exactly what operational efficiency should look like. What drove that? Three primary areas.

Speaker 1

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 field gas. Given the current dislocation between Waha pricing and Henry Hub, we're not making money on our gas at the moment. We're putting it to work in our own operations wherever we can. That's a practical economic decision, and it's paying off. Third, continued electrification across our field operations. That's improving reliability, lowering costs, and positioning us well for the long term. 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 turning line activity represents roughly one-third of our planned 2026 program.

Speaker 1

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. 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. 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. We moved into what we are calling maintenance mode development strategy.

Speaker 1

The goal is simple: hold production roughly flat while maximizing free cash flow. 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 21.5 thousand barrels per $1 million of capital spent to approximately 35.4 thousand barrels per $1 million. That's a significant step change in efficiency. 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.

Speaker 1

That's an add of about 1,000 barrels of oil per day and, but 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 pricing. 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 HighPeak. 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.

Speaker 1

When we look at the market, and more importantly, when we make decisions, we focus on the back end of the curve. What we've seen there is a much more modest move, roughly a $10-$12 increase from around $60 a barrel at the beginning of the year to the low $70s per barrel currently. 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. That's one that reflects sustainable pricing, capital efficiency, and long-term value creation. 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.

Speaker 1

If that happens, it creates a meaningful long-term opportunity for HighPeak. More sustained pricing strength means higher incremental free cash flow for years to come, that's where real value gets created. 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 giving even more exposure. That gives us meaningful upside to stronger pricing. 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. We've got both upside torque and downside protection.

Speaker 1

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 1 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 timeframe 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 on an at-the-market or ATM program in place. This gives us the ability to issue up to $150 million of common stock.

Speaker 1

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. 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.

Speaker 1

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. Disciplined execution is what creates long-term value, and that's exactly what HighPeak is delivering. With my comments now complete, operator, please open the call up for questions. Operator?

Speaker 3

I am so sorry for the technical

Speaker 1

Operator?

Speaker 3

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 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 today comes from Jeff Robertson with Water Tower Research. Your line is open.

Operator

Good morning. Mike, given where you are with production and 60% of estimated 2026 capital going or 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 2026? Any early color or preliminary color on 2027?

Speaker 1

Jeff, great question. You know, as we laid out in our guidance last quarter, you know, we were planning to spend roughly 60% of that budget in the first half of the year. You know, as we've kind of 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. 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.

Speaker 1

You know, 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. 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. You know, and again, yes, it's a little hot to our guided range on the top, you know, above the top end of the guided range.

Speaker 1

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, that we will be in the upper portion of that production range that we guided to originally. For the CapExSpend, the guided range is still very applicable, and I think we demonstrated that in the first quarter.

Operator

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 to get the full benefit of production in the year the wells are being drilled, or as much of it as possible?

Speaker 1

I don't know that we're detailed enough to mic a break, as I like to call it from West Texas slang. I think if you look into 2027, I would assume a very, very similar program to what we had to 2026. There was one question I did not answer, which was how many DUCs we would exit the year at. We will exit with roughly 9 to 10 DUCs in 2026 going into 2027. We would be set up very similarly to do the exact program that we have in 2026, in 2027.

Speaker 1

Again, if you're looking at kind of a CapEx spend in 2027, I think what we have this year at a midpoint of about $270 million is where you need to be, you know, kind of coalescing for modeling purposes.

Operator

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?

Speaker 1

No, that's a great question. You know, Jeff, we've got, you know, upwards to getting now close to 400 horizontal wells that are producing. 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 and 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. 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 look like a good candidate.

Speaker 1

Those are the ones that we went and did. 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, 2-year timeframe to really understand that before we would wanna go and attack a well that's currently producing. You know, these are well interventions that we were going to have to do something. Think on the I like to call it a mini stimulation on the well. Think surfactants, acid, more or less cleaning the well bore out and reducing, you know, damage to the formation that happens over time. We're seeing really good results.

Speaker 1

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

Operator

Ryan, or Mike, you had big working capital swings in the first quarter, which impacted free cash flow, as you noted in your re-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?

Speaker 1

Yeah, great question, Jeff Robertson. If you recall, for the bulk of the fourth quarter, we ran 2 rigs, and we also had a couple of really large simul-frac jobs. We did have a negative working capital swing of about $35 million in Q1. A lot of that is just that capital from the additional rig and a couple of those simul-frac jobs kind of working its way through the system. All that's behind us now, on a go-forward basis, it's more steady state. I wouldn't expect those large capital, working capital swings on a go-forward basis throughout the rest of the year.

Operator

Just lastly, Ryan or Steve, HighPeak 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?

Speaker 1

Yeah, absolutely, Jeff. I think you're referring to a large hedge loss in the first quarter. The way to think about it, total derivatives loss in the first quarter on paper was about $155 million. 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. 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 gonna shrink and any potential cash hedge loss would shrink as well as we kind of progress throughout the year.

Operator

Thank you.

Speaker 1

Thank you.

Speaker 3

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

Speaker 2

Hey, good morning, guys.

Speaker 1

Good morning, Nick.

Speaker 1

Good morning.

Speaker 2

Curious to dig a little bit more on the workovers. I know you have the slide, kind of talking about the benefits of that. It looked like the workover expense for the quarter was actually pretty low relative to kind of what the run rate was in 2025. Just trying to understand, like, I guess, what the activity expectation is going forward. I mean, a lot of wells obviously that you're looking at to potentially, you know, augment with, improve productivity with these workovers. Kind of 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.

Speaker 2

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

Speaker 1

No, great question, Nick. Let me step back to last year and to kind of answer the question as to why overall LOE is down. You know, an LOE is kind of two buckets, right? It's your chemical and day-to-day, everyday LOE, and then it's your workover expense. 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 half to three quarters of 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 tip-top shape. We spent, you know, call it $1-ish or a little bit more per BOE doing that in 2025.

Speaker 1

We only have so many wells. There's always going to be some workover expense. You know, make sure you don't read through that it's going to zero. I think a reasonable run rate for workover expense, probably somewhere in the $0.75-$1.00 range is extremely conservative. You know, obviously we were much lower than that in Q1. To answer your other question about the type of interventions, you know, 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, you know, changing the value of the well after the fact.

Speaker 1

To that, I would say with all the work we did throughout the quarter, some of these were capital workovers in our inner capital spend for the quarter. 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 shaving costs 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. 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 2025, this gives us plenty of money in the budget to do it." I think you're looking at it exactly right.

Speaker 1

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.

Speaker 2

Got it. That makes sense. 1 other piece of this, and I don't know if it's connected or not. I mean, it sounds like it might have been. You know, the I guess second half of last year, you know, as you stepped out into I think it was further to the east, you had some of the issues with kind of finding the, I guess, where you had water encroachment in some of the newer extensional wells. I guess where does that stand? Are those wells I mean, has that area just been kind of written off at this point? And are those wells just not really part of the existing production or any plan going forward?

Speaker 1

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. Yes, we encountered some extraneous water production in that area. You know, we kind of talked about the impact it had on our inventory. The only zone we carried inventory in that little red box was Wolfcamp A. The quick answer is no, HighPeak is not going to drill another well in that little red box, and that equated to about 18 wells coming out of our inventory. The existing wells that we do have there, we've got 3 of those wells producing today. We've done some interventions on those wells to reduce the amount of water coming in, they are very economic.

Speaker 1

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. Absolutely, that had an effect with production kind of in the, you know, second half of 2025. 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.

Speaker 2

Got it. I think I've talked to you about this before, but just, total, I guess, HighPeak water handling and disposal capacity relative to, what y'all are seeing in terms of water volumes currently.

Speaker 1

Yeah, no, Nick, great question. Again, we constantly highlight the infrastructure that HighPeak has put in place over the last 5-plus years. To your question there on the water system, if you look back 2 years, we were running 6 rigs, 3 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. We put in very large pipes, very large pumps, several SWDs. Our SWD capacity is a little over 400,000 barrels of capacity today. These pipelines that are 24 inches in diameter, we can move around 400,000 barrels a day. Of course, we recycle almost 95% of what we use on the stimulation side.

Speaker 1

To give you an idea of where we sit today, where we're producing roughly, you know, on the gross basis of oil that we produce, it's pretty close to 45,000 to 47,000 barrel gross of oil. With that kind of 4 to 1, we're a little over 200, call it 210, 220,000 barrels of water a day being produced across HighPeak. Some of that, you know, a little bit more than 4 times is because you have some flow back from your new fracked wells. We're about 45% to 50% utilized of capacity that HighPeak has. We take very little third-party water into our system. It's available. For folks near and around us, we do have plenty of capacity for disposal.

Speaker 1

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. I think you're seeing that on our LOE cost numbers. 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. Both sides of the equation is what we've attacked, and we've been able to bring costs down across the board.

Speaker 2

Got it. That is all very helpful. Mike, I appreciate the time. Guys, I appreciate the time. Have fun.

Speaker 1

Thanks, Nick.

Speaker 3

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.

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