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Operator: Hello. And welcome to HighPeak Energy 2025 First Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. [Operator Instructions]. I would now like to turn the conference over to the CFO, Steven Tholen. You may begin.

Steven Tholen: Good morning, everyone, and welcome to HighPeak Energy’s first quarter 2025 earnings call. Representing HighPeak today are President, Michael Hollis; Vice President of Business Development; Ryan Hightower, and I am Steven Tholen, the Chief Financial Officer. During today’s call, we make refer to our May investor presentation and our first quarter earnings 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. So, 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.

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, Michael Hollis

Michael Hollis: Thank you, Steve. Good morning, ladies and gentlemen, and thank you for joining us today for HighPeak Energy’s first quarter call. Our conference call will sound a little different today, as Jack is at home recuperating. He’s had a long illustrious history of writing and cutting horse competitions, which is his other passion outside of work. For those who are not familiar with the sport, Quarter Horses are among the most athletic animals on the planet. And recently, one got the better of in during a practice session. The good news is he’s going to be just fine. He’s doing some physical therapy so that he can get back into proverbial saddle as fast as possible. In the meantime, it’s business as usual around here at HighPeak, as well as we all remain fully dedicated to guiding our company through this current volatile market.

Also, we are changing from our historical precedent of referring to each slide as we go through this call. But our comments will stay generally consistent and follow our May investor presentation. With that housekeeping out of the way, let’s talk IP. We’re off to a strong start in 2025, as we delivered another very solid quarter. Our production averaged over 53,000 Boes a day, beating guidance and consensus estimates. This is approximately a 6% increase versus Q4, while maintaining the same oil percentage per Boe. Our strong production rate allowed HighPeak to generate almost $200 million of EBITDA during the quarter, which was an increase of approximately 10% compared to the fourth quarter at nearly the same weighted average oil price. Our cash margins remained healthy and were aided by roughly 3% drop in lease operating expenses quarter-over-quarter.

This is a great time to give a shout out to the HighPeak field organization. They are always finding new and innovative ways to reduce costs. This is an ongoing effort, and I expect it will continue into the future. Another exciting theme that we will discuss is that, we are realizing much higher levels of operating efficiencies in our development program compared to our historical averages. Given the strong start to the year, we are narrowing our production guide and raising the bottom end and increasing the midpoint of beaten rains. Now for an operational update. As I previously mentioned, our operating team is continuing to realize more and more efficiencies, especially on the drilling side of the equation. Over the past 2 quarters, our spud-to-spud timing has dropped from an average of 14 days to about 11 days, which is over 20% faster than our previous expectations.

So what does that mean for HighPeak? This faster pace translates to a single rig drilling over 30 wells per year compared to our average over the past 2 years of about $25 million. As you would expect, there are some associated reductions to our daily variable drilling cost, which translates to lower cost per foot. These drilling efficiencies are sticky, and we expect them to continue on a go-forward basis. So let’s talk about what we accomplished in our first quarter and walk you through our CapEx spend. I’m proud to report that our first quarter D&C costs were in line with our 2025 expectations, and further cost concessions are on the way. HighPeak’s drilling team has significantly outperformed expectations. Increased drilling efficiencies have allowed HighPeak to drill more wells than originally scheduled during the quarter.

We actually spud 20 wells during the quarter, while rig releasing 16 compared to our initial plan of 12. In addition, we outlined on our March conference call, our 2025 infrastructure CapEx was heavily first half weighted with the majority coming in the first quarter. I’m also proud to report that the implementation of these projects went smoothly and within budget. This investment will continue to support our peer-leading margins and will also provide us with operational flexibility and optionality. As one would expect, with our increased drilling efficiencies, we were starting to build additional drilled, but uncompleted inventory as our 2-rig program was outpacing our on frac crew. This is evidenced by the increase in our work in progress well count of 28 at the end of the first quarter.

We typically manage the DUC count to only have true operational DUCs. HighPeak does not like to let invested capital sit unproductive. We made the decision to accelerate the completion of a four-well pad in the first quarter when oil was over $70 a barrel. One side note for those of you studying our first quarter turned in line numbers, these additional four wells were not online at the end of the quarter. So, they will actually show up in our Q2 TIL numbers, but the completion dollars were spent in Q1. As we detailed in our 2025 capital budget guide, we planned on a heavy first quarter spend rate. In March, we estimated we would deploy roughly 35% of our yearly CapEx budget in Q1. We were able to do more work with the same equipment. We accomplished everything that we laid out to do, plus we drilled and completed the four additional wells.

This equated to 38% of our full year budget. By accomplishing all of this in Q1, we have set HighPeak up for a great 2025, while still generating positive free cash flow during the quarter. In fact, if you remove the CapEx associated with the additional four-well pad, we actually would have come in under our expected spend for the quarter. It’s great that the HighPeak development machine is running more efficient than ever. But what does that mean looking forward? Effectively immediately, we are dropping one of our two rigs for a period of four months, May through August, while also modifying our completion schedule with occasional pauses to track our level of operational DUCs. If we were to continue our two-rig program at the current cadence, we would expect to drill approximately 65 wells this year, which is 30% more than our budgeted drilling activity.

Given the current macro environment, now is not the time to lean in and drill more wells than our initial plan. We are going to take our foot off the gas and like we’ve always said, we will be fast on the brake and slow on the accelerator. The overall effect of this updated development plan will allow us to stay within our original guided 2025 activity levels. Due to our increased operational efficiencies, we will still expect to complete the same number of wells as we originally guided to back in March. We also feel confident that this revised plan, we will stay within our capital budget guide for the year. Additionally, I do want to stress that if the current market environment worsens, or commodity prices further weaken, we always have the ability to modify our development program.

HighPeak has total flexibility from a land and operations perspective to reduce the budget and leave a rig down for longer or make any other appropriate changes to slow our capital spending, depending on market conditions. So, speaking of the current market environment, I’ll talk a little bit about its effect on our current drilling and completion costs. Tariffs, who knew that one tweet could move global markets and affect the business world to the extent it has over the past month. For HighPeak, the biggest effect tariffs have on our immediate cost is on OTCG products, i.e., casing and tubular goods, the steel products that we use in drilling and completing our wells Our cost of tubular goods for the remainder of the year is up roughly 3%.

OTCG goods make up approximately 8% of our typical AFE. So the effect of a 25% tariff on all of our tubular goods could increase our overall AFE by roughly 2%, if it applied to all of our tubular goods. HighPeak thankfully utilizes US-made steel products for the vast majority of our OTCG needs. Hence, they are not subject to import tariffs and the effect on our cost is less than what many of our peers are facing. The good news, we are seeing savings across the board on all AFE items, except the OTCG products. Presently, we’re seeing low single-digit overall declines in well cost inclusive of those increased OTCG prices. Lastly, the prescribed completion pauses and the softness in the OFS market will make it possible for HighPeak to implement some further efficiency changes to our 2025 plan.

HighPeak will begin final frac operations on some of our multi-well pads, further reducing our already peer-leading per foot development cost. The operations team have done a fantastic job over the last couple of years, incrementally getting more efficient. We have been picking up pennies and nickels everywhere we can. It’s been quite some time since we had dollar bills worth of efficiencies to pick up. But simu-fracking represents a dollar bill size step change in our cost structure. And for those of you updating your models, please note that we have not factored in any of these savings into our 2025 capital budget. This market continues to remain very volatile, and we like to operate with a conservative mindset. At this point, I would like to turn the call over to Ryan Hightower.

Ryan Hightower: Yes. Thanks, Mike, and good morning, everyone. As a quick recap, as many of you know, we built HighPeak old-fashioned way, primarily through grassroots leasing and production growth through the drill bit, which is not the norm in today’s public E&P world. And as you may recall, in our March investor presentation, we included a slide detailing our year end 2024 reserves, which showed HighPeak having a 345% reserve replacement ratio last year. And now that all of our public peers have filed their 10-K and year end reserve report, we wanted to go back and study how HighPeak measured up compared to the peer group. So we looked at all of our peers’ reserve replacement ratios over the last three years. It’s a small chart, but on slide 9 of our investor presentation, you can see that HighPeak has realized a 400% reserve replacement ratio over the past three years, which is almost exclusively driven through organic growth.

And you can also see how our reserve replacement, both from an overall and an organic perspective compares favorably to the peer group. We also wanted to look at where the industry and HighPeak stand from a profitability standpoint at today’s near $60 oil price. The other slide — the other chart on slide 9 shows everyone three-year all-in finding and development costs plus their operating costs while adjusting each respective companies realized oil price to $60 a barrel. The results of this comparison show that as a whole, the peer group is marginally profitable at today’s prices. However, it also highlights, HighPeak outsized level of profitability due to our superior cost structure and higher profit margins per BOE and while it’s great that we can develop profitable reserves at this price point.

As Mike said, we don’t think it’s the appropriate time to really lean in and increase activity in this current market. Few other things to note. First, we believe that using all-in F&D cost is appropriate because whether you’re an equity investor or a debt investor, not only are you investing in a particular asset but you’re also investing in management’s ability to allocate capital resources, whether the capital is invested through drilling activity or through acquisitions or a combination of the two. And as shown on the chart, HighPeak has successfully allocated capital over the past three years. Second, we get a lot of inbounds from investors who acknowledge that we do have really great single-well economics but that over the past few years, we’ve had to invest quite a bit of capital in our infrastructure system in order to realize those great single well economics.

This chart includes our total CapEx, which is inclusive of our infrastructure investment. And as you can see, from an all-in CapEx perspective, HighPeak stack up very favorably to the peer group. And moving forward, it’s also important to remember that our infrastructure budget will drop significantly. The investment we’ve made over the last few years will drive HighPeak capital efficiency for the life of our field. Here at HighPeak, we’ve always been ahead of the curve from a technical perspective, which is what afforded us the opportunity to get in front of the broader industry and put our position together organically. This was driven by management’s extensive in-basin experience local geologic knowledge and the amount of technical work we’ve conducted on our area.

We’ve always been on the forefront, having to educate and prove to the rest of the industry that our rock is good. So now after drilling over 350 wells targeting six different benches and producing 80 million BOEs, it’s nice to see the industry and various third-party research groups beginning to recognize the value of our position and the extent of which we have expanded the boundary of the play in our operating areas. I’ll now turn the call back over to Mike to wrap things up.

Michael Hollis: Thanks, Ryan. In closing, we typically would pass to Jack. So, I’ll paraphrase some of his comments, as they pertain to HighPeak’s core pillars; improving corporate efficiency. Our operations are running smoother and more efficiently than ever, while continuing to keep our costs in line with our expectations. Additionally, we see further savings on the horizon, which we would expect to lead to increased overall levels of corporate efficiency, maintaining capital discipline. Due to the current state of global economic uncertainty and its impact on oil prices, we have taken the proactive step to modify our development plan. Again, due to our significant realized efficiency gains, we still expect to complete the same level of development activity this year.

We will remain and continue to monitor market conditions. And we will remain flexible to further adjust our program as conditions warrant, optimizing our capital structure. One of our main objectives this year is optimizing our capital structure, and we remain committed to executing our plan once the capital markets stabilize. In the meantime, we are currently in a healthy financial position with no near-term debt maturities. And we are taking proactive steps to keep our balance sheet strong, creating shareholder value. This is the time to stay nimble and prudent, which our high-quality asset base allows us to do. As large owners of the company, management is fully aligned with our shareholders and has a long-term outlook on value creation.

It’s important to remember that while markets may be temporarily volatile, the fundamental value of our asset base is still strong. We are fortunate to have a long runway of high-value drilling locations at a time when core inventory is becoming increasingly scarce. And we have the ultimate flexibility to develop our inventory when market conditions provide for realizing maximum value. Thank you, and with our comments now complete, I’ll open up the call to questions from our analysts.

Operator: Thank you. [Operator Instructions] Our first question comes from the line of Noah Hungness with Bank of America. Your line is open.

Noah Hungness: Good morning guys. For my first question here, I was hoping you could talk about what kind of impact you are seeing or you think you’ll see on the use of simul-frac and how — and what the per foot D&C cost kind of impact is once that gets implemented?

Michael Hollis: Great question. No. Again, like I said in the prepared remarks, it’s been a while since we’ve been able to pickup what I call dollar bill size, the efficiencies in our program because, again, as you get pretty mature in a basin, you try to implement all of the tools that you have at your disposal. So again, when we were running two rigs and one frac crew at the pace we were drilling in the last couple of years with two rigs, it fit with just what we call zipper fracking, which would be fracking single wells at a time with the frac crew. It was a very balanced equilibrium kind of program. So fast forward to where we are today, obviously, slowing down the program, taking some pauses in our frac schedule, allows us to be able to pause a little longer and then be able to frac utilizing the final frac technique.

That’s just basically we’re going to frac two wells at a time zippering between four wells two at a time. So what that does is that reduces the amount of days and time and cost that you have for completing those same four wells. I’ll put it in perspective for you. Fracking 4 wells assume they’re 15,000-foot laterals in our area typically takes 25 to 28 days to complete fracking those four wells. Doing it with the simul-frac process, we’ll cut that in half, call it somewhere in the 11 to 14 days to frac. So again, all of your variable costs change, everything goes into that. So for a 15,000-foot lateral, you will typically see about $250,000 of savings per well. So on that pattern, we would assume about $1 million of savings for the entire DC E&F process.

So again, if you took $1 million over that would be 30,000 or 60,000 lateral feet, that will give you an idea of $1 per foot savings at the final frac process will help. Now there’s some ancillary benefits to doing simul-frac. It’s been a while since companies have actually made that change, right? Everybody does it now because they have bigger programs, more rigs to where you can feed a signal frac crew. But if you go back four or five years ago, what most operators experience was whenever you did that, one, you always have a certain amount of your production that’s impacted by the fracs of nearby new wells, right? We call that watered out. So instead of watering out offset production for 28 days, — as we go forward, we’ll only be watering those out for half that time.

Also, again, we get to bring that production on. So throughout this year, those wells will be on production longer than they would have been with our original plan. You also get the benefit of bringing forward a couple of these pads in time because it only took 14 days to frac them and then we do the rest of our work to drill them out with the pump and turn them on. So we will pull forward a little bit of production from a timing standpoint into 2025. So again, when you look at the benefits of doing this, not only are we drilling a little faster, right, that we’re now 25% plus faster than we were a year ago, there’s variable cost savings on the drilling front. And then on the completion side, obviously, cheaper dollar per foot to complete the well is exactly the same way you are going to complete them.

Getting them online faster and watering out left. So it’s kind of — it’s a win-win, win-win in the whole process.

Noah Hungness: That’s helpful color. And then for my second question, I was hoping you guys could give us maybe a little update on where leading edge results are in Borden County and kind of how you see productivity for those wells comparing to kind of the legacy stuff for the stuff that you are drilling and completing in Northern Howard County?

Michael Hollis: You bet. Great question, Noah. Obviously, we’re very excited about the well performance that we’re seeing up in Borden County. Today, we’ve got eight wells that have been producing for quite some time. We’ve got a four-well pad up in Borden on our northern portion of our block that’s been in flowback now for a week or two that looked just like the original eight wells. And I guess that’s a good point. If you go back to fourth quarter presentation that we had put out, we have some detail on what our most recent wells look like in kind of a 180-day flowback period. Again, roughly 20% better than what we had the year prior. Again, those eight wells were in that mix and part of that production performance. The new four wells that we are flowing back today look just like — and that’s in three different zones.

That’s Wolfcamp A, Lower Spraberry and Middle Spraberry. And all three of those zones are performing just as we had expected and are part of that 20% improvement in kind of oil production in the first 180 days. And also, we have a four-well pad that’s right offset some of this production that will be our very first simul-frac pad. So in the next couple of weeks, we will be implementing that first simul-frac.

Noah Hungness: That’s its guys. Thank you.

Michael Hollis: You bet. Thank you, Noah.

Operator: Our next question comes from the line of Jeff Robertson with Water Tower Research. Your line is open.

Jeff Robertson: Thank you. Mike, you mentioned the Middle Spraberry in Borden County. I remember in the fourth quarter conference call, you talked about the ability to increase your number of economic development locations with the Middle Spraberry. Can you give an update on where you stand with that?

Michael Hollis: Absolutely, Jeff. The Middle Spraberry is a very exciting development for HighPeak. Obviously, today, we only have two Middle Spraberry that are producing. Both of those wells are well below $50 breakeven prices, I think kind of low single — or low 40s for a breakeven. Now again, they’re right in the middle of our northern block that we call Flat Top. Off to the west, right on the west flank of Flat Top, Surge operating or Moss Creek has drilled five additional Middle Spraberries. So it’s a little early in the game to be able to say all of the wells that we have in our inventory. There’s about 200 Middle Spraberry wells that we have in inventory up in our Flat Top area. So I would think over the next several quarters as we drill and prove up the same kind of performance across our entire Flat Top acreage that we would be able to feel comfortable for the Street that we would be able to let them know, hey, these wells are now sub-$50 breakeven.

And again, about 200 of them would move over into that category. So today, we sit at about 1,000 wells that are below $50 breakeven. And obviously, we’re drilling about 50 a year. So I would think over the next, call it, year or so, we would be able to move 200 additional wells into that category of sub-$50 breakeven. So again, as we’re developing at the pace we are over the next couple of years, it would be reasonable to expect that our sub-$50 breakeven inventory count will actually go up.

Jeff Robertson: If you look at the changes you’re making to the 2025 development plan with the dropping the rigs in the summertime and creating some space in your completions calendar to be able to use simul-fracs and the benefits play out the way you think they will. How will that have an impact on your go-forward development plan in 2026 in terms of being able to keep those efficiencies that you’re gaining this year?

Michael Hollis: Jeff, that’s a great question. Obviously, we’ve got to work very closely with our vendor partners. So today’s market makes it obviously very easy to kind of turn this system. If everybody was very busy and all of the frac crews had work, to put pauses in place, you would have to work with that vendor much more closely. So again, if you look into 2026, if the market improved, now we would have a track record of doing this with that specific frac crew. And we would probably have to work with some of our other E&P partners out in the basin to be able to work a schedule out to where that frac company doesn’t have their equipment sitting and not generating revenue for too long of a period. But again, that’s only going to be predicated on everyone getting busier, and again you would have, hopefully, some oil price support there.

So, we’re very encouraged, and we’re working with our partners very closely that we will be able to keep this efficiency built into the system and have it sticky going forward.

Jeff Robertson: You raised the floor of production guidance to 48,000 Boe days. Is that mainly due to first quarter performance without factoring in any potential benefits from maybe decreased downtime as you move towards simul-fracking in the second half of the year?

Michael Hollis: You bet, Jeff. So again, there’s been a whole lot of volatility and changes in the market over the last call it, month and half, right? So when we look at changing guidance, we try to be extremely conservative. Again, it’s always a good thing to be able to beat and raise. So, with the really strong first quarter production that we had, all of the efficiencies that we talked about — so again, we plan to do the same work in 2025 that we originally laid out to do. We just did a little bit of that work sooner into Q1. And what that means is you have some wells that we’ll be producing longer in 2025 than they would have read-through to that would be slightly higher yearly production. It would be reasonable to assume come Q2 that we’re looking forward to the opportunity of continuing to have very strong production and that we would be able to reach out and say we’re now tightening up again the CapEx spin and range, and we’re also increasing our production levels.

Again, a good way that we look at this as 50,000 Boes a day flat. Again, we’re doing large pad developments. So there will be some lumpiness in that number 53, the next quarter could be 50, it could be 49 and then you may have another 53 in there, but I think that average is going to be well-above the midpoint of our guided range.

Jeff Robertson: Then on the balance sheet, I think you mentioned on the last call that with the infrastructure investment in 2025, that could clear the way for less maintenance capital requirements in 2026, which would potentially result in more free cash flow. Is it — how much of the balance sheet recapitalization goal is to position it, so that you have the flexibility to reduce leverage from time to time with free cash flow at par as opposed to dealing with the amortization on the current term loan?

Steven Tholen: Jeff, again, a lot to unpack there, but this is all great stuff. Corporate efficiency is what the goal is here, right? Over the last four years, as Ryan walked everybody through in the prepared remarks, we’ve spent a lot of necessary capital over the last few years, building out the infrastructure such that the high peak machine, again, with inventory for decades that breakeven sub-$50, we wanted life-of-field infrastructure in place such that we could increase, decrease as we needed and as market conditions dictated throughout the life of this field. So you bring up a great point. If you look at CapEx spend at each one of the years or quarters in HighPeak’s history, a very large portion of that CapEx every quarter has been infrastructure.

Today, the infrastructure is in place. As we go into — and you’re going to see that for the rest of this year, again, with our CapEx spend that we had in Q1 of $179 million. When you look at the midpoint of our CapEx range and you subtract the $180 million from it or $179 million, and you divide by three, you’re going to have a pretty good idea of what we’re going to be spending per quarter. So I don’t think you have to wait until 2026 to see that corporate efficiency step change. And again, it’s going to be somewhere in the $100 million to $110 million we would spend in each one of these quarters, still producing 50-plus thousand Boes a day, again, in any model that you’re running at any reasonable oil price, you’re going to see that we’re going to generate significant free cash flow.

So your second kind of part of that question, I think, is very important. One, we want to optimize our capital structure for HighPeak. Again, typically, that would mean a normal way financing with high-yield bond and be reasonable to expect that you have a fairly large RBL and again that RBL typically, you like to keep that well under 50% drawn when you kind of in a hurdle. So with that, we would have significant ability over the next couple of years to pay down our net debt at par, off of the RBL. And again, a typical normal way high-yield bond usually has a two-year kind of no call to provision. So we would have that kind of two-year period to pay down debt on the RBL at par. So again, allowing us a whole lot of flexibility with our — to be able to utilize that large amount of free cash flow we’re going to be generating.

So great question, Jeff.

Jeff Robertson: Thank you.

Michael Hollis: You bet.

Operator: Thank you. Ladies and gentlemen, I’m showing no further questions in the queue. That does conclude today’s conference call. Thank you for your participation. You may now disconnect.