HighPeak Energy, Inc. Q1 FY2025 Earnings Call

Hello and welcome to HighPeak Energy's First Quarter Earnings Conference Call for 2025. At this moment, all participants are in listen-only mode. After the presentation by the speakers, we will have a question-and-answer session. I would now like to hand the call over to the CFO, Steven Tholen. You may begin.

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 will 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.

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 him 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 the proverbial saddle as fast as possible. In the meantime, it's business as usual around here at HighPeak, 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 a 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 guidance and raising the bottom end while 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 two 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 two years of about 25 million dollars. 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 that 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 are starting to build additional drilled but uncompleted inventory as our two-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, as 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 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 efficiently 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, from 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 with 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 keep 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. Thankfully, HighPeak 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 is 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. Our operations team has 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-sized 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.

Thank you, Mike, and good morning, everyone. To recap, we built HighPeak through grassroots leasing and production growth, a strategy that stands out in today's public E&P landscape. In our March investor presentation, we shared our year-end 2024 reserves, showing a 345% reserve replacement ratio. Now that all our public peers have filed their 10-K and year-end reserve reports, we revisited how HighPeak compares with the peer group. Looking at reserve replacement ratios over the last three years, we found that HighPeak achieved a 400% reserve replacement ratio, primarily through organic growth. Our reserve replacement, both overall and organic, compares favorably to the peer group. We also examined the profitability of the industry and HighPeak at the current near $60 oil price. A chart in our investor presentation illustrates that the peer group is only marginally profitable at current prices, while HighPeak demonstrates significantly higher profitability owing to our superior cost structure and profit margins per BOE. Although we can develop profitable reserves at this price point, we agree with Mike that it isn’t the right time to ramp up activity in this market. Additionally, we believe that an all-in finding and development cost is pertinent for both equity and debt investors, as it reflects management's ability to allocate capital resources effectively, whether through drilling or acquisitions. HighPeak has successfully managed capital allocation over the past three years. We've received feedback from investors recognizing our excellent single-well economics, although we've had to invest substantially in our infrastructure to achieve these results. Our total CapEx, including infrastructure investment, shows that HighPeak is favorably positioned compared to peers. Moving forward, our infrastructure budget is expected to decrease significantly, enhancing our capital efficiency over the field's lifespan. At HighPeak, we've always led in technical expertise, which allowed us to position ourselves ahead of the wider industry through organic growth. This leadership is supported by management's experience and in-depth local geological knowledge. After drilling over 350 wells, targeting six different benches and producing 80 million BOEs, it’s gratifying to see the industry and various third-party research groups starting to appreciate the value of our position and how we've expanded our operational boundaries. I'll now turn the call back over to Mike for closing remarks.

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 continue to monitor market conditions and 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 while 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. We have the ultimate flexibility to develop our inventory when market conditions allow us to realize maximum value. Thank you, and with our comments now complete, I’ll open up the call to questions from our analysts.

Thank you. Our first question comes from Noah Hungness with Bank of America. Your line is open.

Good morning. For my first question, could you discuss the impact you are seeing or expect to see from the use of simul-frac and how it might affect the per foot drilling and completion cost once it's implemented?

Great question. No. Again, like I said in the prepared remarks, it's been a while since we've been able to pick up what I call dollar bill-sized 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 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. Fast forward to where we are today, obviously, slowing down the program and 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. What that does is reduce 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 four wells that are 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, calling 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 D&C process. If you take $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. Now there are 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 and more rigs to where you can feed a signal frac crew. But if you go back four or five years ago, what most operators experienced was that 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. Looking at the benefits of doing this, not only are we drilling a bit faster; right? We're now 25% plus faster than we were a year ago, there are variable cost savings on the drilling front. And on the completion side, obviously, cheaper dollar per foot to complete the well is just the same way you are going to complete them. Getting them online faster and watering out less. So it's kind of a win-win-win in the whole process.

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?

Absolutely, great question, Noah. We're very excited about the performance of our wells in Borden County. Currently, we have eight wells that have been producing well for a significant period. We also have a four-well pad in the northern section of our block that has been in flowback for a week or two and is performing similarly to the original eight wells. If you refer to our fourth quarter presentation, you will find details on our latest wells over a 180-day flowback period, showing about a 20% improvement compared to the previous year. The eight wells are included in that performance data. The new four wells currently in flowback are also performing well across three different zones: Wolfcamp A, Lower Spraberry, and Middle Spraberry. All three zones are delivering the expected results, contributing to the 20% increase in oil production in the first 180 days. Additionally, we have another four-well pad that will be our first simul-frac pad, which we plan to implement in the next couple of weeks.

That's it guys. Thank you.

You bet. Thank you, Noah.

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

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?

The Middle Spraberry is an exciting development for HighPeak. Currently, we have two producing Middle Spraberries, both with breakeven prices considerably below $50, probably in the low 40s. They are situated in the middle of our northern block known as Flat Top. To the west, Surge operating or Moss Creek has drilled five additional Middle Spraberries. It's still early to provide a full assessment of all our wells, but we have about 200 Middle Spraberry wells in our inventory in the Flat Top area. Over the coming quarters, as we drill and validate similar performance across our Flat Top acreage, we will feel more confident in communicating to the market that these wells will fall into the sub-$50 breakeven category. We expect around 200 of them to qualify. Currently, we have approximately 1,000 wells below the $50 breakeven mark, and we are drilling about 50 annually. It’s reasonable to anticipate that within the next year, we could classify an additional 200 wells as sub-$50 breakeven. As we continue our development at this rate over the next few years, our count of sub-$50 breakeven wells is likely to increase.

If you look at the changes you're making to the 2025 development plan with dropping the rigs in the summertime and creating some space in your completions calendar to be able to use simul-fracs, how will that impact your go-forward development plan in 2026 in terms of keeping those efficiencies that you're gaining this year?

Jeff, that's a great question. Obviously, we’ve got to work very closely with our vendor partners. Today’s market makes it very easy to 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. If you look into 2026, if the market improves, we would have a track record of doing this with that specific frac crew. 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 so that the frac company doesn’t have their equipment sitting and not generating revenue for too long of a period. That’s only going to be predicated on everyone getting busier, and again, you would have, hopefully, some oil price support there. We’re very encouraged, and we’re working with our partners closely to ensure we will be able to keep this efficiency built into the system and have it stick going forward.

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?

You bet, Jeff. There has been a lot of volatility and changes in the market over the last month and a half. When we consider changing guidance, we aim to be extremely conservative. It’s always a positive outcome to be able to exceed expectations and enhance guidance. Given our strong first quarter production and the efficiencies we discussed, we plan to execute the same work in 2025 as we originally intended. We completed some of that work earlier in Q1, which means some wells will produce for a longer duration in 2025 than initially planned, resulting in slightly elevated yearly production expectations. It is reasonable to assume that by Q2, we look forward to maintaining robust production levels while tightening our CapEx spending range and increasing production levels. A useful point of reference is to consider an average of 50,000 Boes per day. We're engaged in large pad developments, so there will be fluctuations in that number; in the next quarter it could be 53, 50, or 49, or even another 53, but I believe the average will exceed the midpoint of our guided range.

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. 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?

There's a lot to discuss here, but it's all positive. Achieving corporate efficiency is our primary objective. Over the past four years, as Ryan indicated in the prepared remarks, we have invested significantly in building our infrastructure to ensure that the HighPeak operations can manage inventory efficiently for decades at breakeven costs below $50. We aimed to establish long-term infrastructure so we could adjust operations based on market conditions throughout the life of the field. You made an important observation. If you analyze the CapEx spending in HighPeak's history, you'll see that a substantial portion of that expenditure each quarter has gone towards infrastructure. Presently, that infrastructure is fully established. Going forward, you'll notice our CapEx spending of $179 million in Q1 will continue this trend for the rest of the year. If you take the midpoint of our CapEx range, subtract the $179 million, and divide by three, you'll have a good estimate for our quarterly spending. The change in corporate efficiency won't be something you'll have to wait until 2026 to witness. It will likely be in the range of $100 million to $110 million per quarter, all while producing over 50,000 Barrels of Oil Equivalent per day. In any reasonable oil price scenario, we expect to generate substantial free cash flow. The second part of your inquiry is crucial. We aim to optimize HighPeak's capital structure. Generally, this would entail typical financing through high-yield bonds. It's reasonable to assume that we will maintain a substantial Reserve-Based Lending (RBL) facility, keeping it under 50% drawn in line with that benchmark. In the foreseeable future, we will have a strong capacity to pay down our net debt at par using the RBL. Most high-yield bonds include a two-year no-call provision, allowing us time to reduce our RBL debt at par. This will offer us considerable flexibility with our significant free cash flow. Great question.

Thank you.

You bet.

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.