HPK

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 one one on your telephone. You'll then hear an automated message advising your hand is raised. To withdraw your question, please press star one one 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.

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.

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.

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 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.

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.

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.

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 1/3 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. 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.

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 21,500 bbl per $1 million of capital spent to approximately 35,400 bbl 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 bbl of oil per day to about 2,600 bbl of oil per day.

That's an add of about 1,000 bbl 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.

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.

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.

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 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.

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.

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?

I am so sorry for the technical

Operator?

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 one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one 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.

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?

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.

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.

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 CapEx spend, the guided range is still very applicable, and I think we demonstrated that in the first quarter.

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?

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 nine 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. 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.

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?

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.

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, two-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.

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.

Ryan, or Mike, you 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?

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 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.

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?

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.

Thank you.

Thank you.

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

Hey, good morning, guys.

Good morning, Nick.

Good morning.

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. 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.

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 a dollar-ish or a little bit more per BOE doing that in 2025.

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.

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.

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.

Got it. That makes sense. One 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?

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 three 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.

They're just lower production because you're only producing from, call it 4,000 ft 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.

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.

Yeah, no, Nick, great question. Again, we constantly highlight the infrastructure that HighPeak has put in place over the last 5+ years. To your question there on the water system, if you look back two years, we were running six rigs, three frac crews, and looking to build to 75,000 bbl-100,000 bbl of oil a day. Now, with that, you need to be able to handle 400,000 bbl of water per day. We put in very large pipes, very large pumps, several SWDs. Our SWD capacity is a little over 400,000 bbl of capacity today. These pipelines that are 24 inches in diameter, we can move around 400,000 bbl a day. Of course, we recycle almost 95% of what we use on the stimulation side.

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 bbl-47,000 bbl gross of oil. With that kind of four to one, we're a little over 200,000 bbl, call it 210,000 bbl, 220,000 bbl of water a day being produced across HighPeak. Some of that, you know, a little bit more than four times is because you have some flow back from your new fracked wells. We're about 45%-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.

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.

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

Thanks, Nick.

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.

Good day, and thank you for standing by. Welcome to the HighPeak Energy, Inc. 2025 fourth quarter earnings conference call. At this time, participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. To ask a question during the Q&A session, please press *11 on your telephone. You will then hear an automated message indicating your hand is raised. To withdraw your question, please press *11 again. Please be advised today’s conference is being recorded. I would now like to hand the conference over to your speaker today, Steven W. Tholen, Chief Financial Officer. Please go ahead.

Good morning, everyone, and welcome to HighPeak Energy, Inc.’s earnings call. Representing HighPeak Energy, Inc. today are President and CEO, Michael L. Hollis; Executive Vice President, Ryan Hightower; Executive Vice President, Daniel Silver; Senior Vice President, Chris Monday; and I am Steven W. Tholen, the Chief Financial Officer. During today’s call, we may refer to our March investor presentation and press release which can be found on HighPeak Energy, Inc.’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. 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 March investor presentation. I will now turn the call over to our President and CEO, Michael L. Hollis.

Thank you, Steve. Good morning, everyone, and thank you for joining us. I thought about kicking off things today by walking through our 2025 results and the execution of our business plan, but that feels like a whole different world today. I am far more energized by what lies ahead than by revisiting what is already behind us and implemented. For anyone interested in a deeper look at the changes that brought us to this point, our prior quarter’s investor presentation and earnings call transcript offer a comprehensive overview. So with that, let us turn the page and talk about 2026 and how we are positioning the company to move forward with purpose, confidence, and a whole lot of momentum. In today’s fast-moving geopolitical and commodity landscape, we are approaching 2026 with focus and discipline. Our focus is clear: protect profitability, maximize cash flow, and strengthen the foundation of our business, not pursue growth for its own sake. Over the past several quarters, we have taken a hard, honest look at every part of our business, and that work continues today. It has given us a firm handle grounded on financial discipline and operational excellence. This means a plan we can fully and confidently execute within cash flow, sustaining stable production with minimal capital intensity, and driving further efficiency gains to expand margins. Our top financial priority is strengthening the balance sheet. As commodity prices rise, incremental cash flow will be directed first toward debt reduction and liquidity improvement. To support that objective, we are taking several decisive steps. First, we right-sized our annual capital budget to ensure our development program stays within cash flow even in a much softer price environment. Second, we expanded our hedging program to reduce exposure to volatility and secure pricing that supports continued investment and debt reduction. Third, we suspended our dividend, which will increase annual liquidity by an estimated $20 million to $25 million. The reality is the market was not giving us credit for the dividend, and most of the investors we speak with regularly have shared that same perspective. We believe that capital is far better deployed strengthening the balance sheet and building long-term value for our shareholders. We are positioning the company to thrive not just for the next couple quarters, but for years to come. Our 2026 development plan is intentionally conservative and built for durability. It is anchored around one drilling rig and roughly one completion crew, which positions us to drill about 30 wells and bring 36 to 38 wells online over the course of the year. We designed this pace of development with three clear objectives in mind. First, to ensure we operate fully within cash flow, covering every financial obligation even if oil prices settle in the mid to upper $50s. Second, to maximize free cash flow in a stronger commodity environment so we can accelerate debt reduction. And third, to maintain strict cost discipline across the organization. Given the recent strength in oil prices, this is an opportune time for us to lean into debt reduction and continue improving our financial footing. Our 2026 program also reflects a balanced approach between investing in new wells and optimizing our existing base production. You can see that balance clearly in our capital allocation. Our capital budget is nearly 50% lower than last year, while unit lease operating expenses per BOE are modestly higher as we invest in targeted initiatives to enhance base production. The result is a development program built for capital efficiency, highlighted by an estimated 65% increase in production per dollar invested. And the early results are encouraging. Quarter-to-date, production is averaging more than 46,000 BOE per day. That is roughly 10% above the midpoint of our 2026 guidance range, even after accounting for the impacts of Winter Storm Firm. Based on today’s market environment, we believe production in the low to mid-40,000 BOE per day range represents a sustainable baseline for our 2026 budget and our plans to reduce absolute debt. Stepping back, it is important to recognize how the market is valuing companies like ours today. In the current environment, SMID-cap E&Ps are rewarded for durable free cash flow, balance sheet strength, and meaningful high-quality inventory depth. What they are not rewarded for is headline production growth. Now there are a few realities shaping our industry right now. Core Permian inventory is becoming increasingly strategic. Tier one shale inventory is finite. Future wells will naturally move down the quality curve as inventory tightens. And preserving and expanding high-quality inventory is what drives long-term value. Now with that in mind, our guiding principle is straightforward: return on capital employed matters more than production growth. Disciplined development today allows us to protect and preserve our tier one inventory for a future time when our financial capacity and a strong, sustained commodity environment align. What are we doing to support this strategy? Our disciplined approach centers on several key priorities. First, we are protecting liquidity and reinforcing our financial position by eliminating the dividend and expanding our hedge position. Second, we are moderating drilling activity so the business remains cash flow neutral even if oil prices move down into the mid to high $50s, while still positioning us to accelerate debt reduction if prices remain strong. Third, we are investing in optimizing across our base production, generating incremental volumes and cash flow without the capital intensity that comes with drilling new wells. And finally, we have continued to delineate additional high-return inventory across our acreage, expanding the long-term opportunity set for the company. Taken together, these actions position HighPeak Energy, Inc. to increase free cash flow, reduce leverage and potentially lower our cost of capital in the future, preserve premium inventory for periods of sustained stronger commodity prices, expand our strategic optionality—whether through drilling, production optimization, or potential accretive M&A—increase long-term NAV realization for shareholders, and ultimately, implementing these key priorities will strengthen the value of our equity. Let me take a moment to talk about our capital allocation philosophy, because it is the backbone of long-term shareholder value. Our approach, again, is straightforward and disciplined. We will protect the balance sheet; a strong financial position gives us the flexibility to navigate commodity cycles and act when appropriate and opportunities present themselves. We will prioritize high-return investments; every dollar we deploy must earn its place, whether it is drilling a new well, optimizing existing production, reducing debt, or pursuing strategic opportunities. We will preserve premium inventory; tier one drilling locations are finite across the industry and disciplined development today safeguards the long-term value of those assets. And finally, we will focus on generating sustainable free cash flow that strengthens the balance sheet, allows us to potentially lower our cost of capital in the future, and ultimately supports a higher long-term equity valuation. When you look at the 2026 development plan through that lens, every decision—from reducing activity levels, eliminating the dividend, expanding our hedging program—is designed to enhance the durability and long-term value of the business. Simply put, our goal is not to grow the fastest. Growth should be the outcome of a well-executed, financially solid plan. This does not happen overnight. HighPeak Energy, Inc.’s goal is to build a resilient, valuable company that delivers for shareholders over the long haul. A key part of our capital efficiency strategy in 2026 is the continued optimization of our existing production base. These efforts include targeted well workovers, artificial lift enhancements, and other operational improvements designed to increase recoveries from wells already online. Projects like these typically generate strong returns on invested capital and allow us to unlock additional value from assets we already own. It is a practical, high-return way to drive incremental volumes and cash flow without the capital intensity of new well drilling. Let me now provide a quick operational update across our core development areas. At Flat Top, our results in the North Borden area—see slide 6 of our presentation—continue to demonstrate strong performance in both the Lower Spraberry and Wolfcamp A. These wells are delivering outcomes comparable to what we see in our core Flat Top area, which reinforces the quality and consistency of this acreage. The northernmost row of wells in our North Borden area is the only part of the field that will require minimal incremental infrastructure, and we expect that work to take place in tranches beginning in late 2026 and into 2027. Now in the core of the Flat Top area, we will continue developing Lower Spraberry and Wolfcamp A locations using the infrastructure already in place, driving corporate efficiency higher. In the Northeast Flat Top area, highlighted by the small red box also on slide 6 of our March investor deck, six wells experienced anomalous water inflows. We completed remedial work on several of those wells and are seeing encouraging early results. Because of the presence of the water flows, our 2026 plan includes no new drilling in the Northeast Flat Top area. Instead, we are focused on maximizing value through the remediation and optimization of the existing producing wells. Importantly, the impact to our long-term inventory is minimal. Even if we chose not to drill any additional wells in this area, it would affect only 18 Wolfcamp A locations that we carry in inventory, as we do not carry any additional zones in inventory for this area. We are also seeing encouraging progress in delineating the Middle Spraberry across both HighPeak Energy, Inc. and our offset operators. There are now nine successful producers, and we expect that momentum to continue with roughly six additional delineation wells planned between HighPeak Energy, Inc. and our offset operators in 2026. Our long-term objective for the Middle Spraberry is clear: convert more than 200 Middle Spraberry locations at Flat Top into fully delineated sub-$50 breakeven inventory. At Signal Peak, we will continue developing our core area in the Wolfcamp A and Lower Spraberry, both of which continue to deliver strong, consistent results—see slide 7 of the presentation. Beyond those core zones, Signal Peak holds substantial upside. We have demonstrated Wolfcamp D performance across the field in two different landing zones. With results that closely track one another, the resource is clearly present across the acreage, and it is not going anywhere. We have not drilled a Wolfcamp D well in roughly three years; however, during that time, the industry has made meaningful strides in optimizing deeper wells. We will continue to evaluate the development of the Wolfcamp D to determine when the economics fully support those wells competing for capital. We also see additional long-term potential in the Middle Spraberry, Wolfcamp B, and Wolfcamp C formations, which add further depth and optionality to our inventory over time. Our drilling results and technical work continue to reinforce what we believe is one of the deepest premium inventories among SMID-cap operators. Today, HighPeak Energy, Inc. has more than 2,600 total drilling locations across the stacked Spraberry and Wolfcamp formations. At our current cadence of drilling, that includes more than 30 years of high-return inventory in the Wolfcamp A, Lower Spraberry, and Middle Spraberry alone, over 100 total rig-years of inventory across the full stack. This level of inventory depth meaningfully differentiates HighPeak Energy, Inc. from most of our peers. One point that we believe the market continues to underappreciate is the growing scarcity of tier one shale inventory across the Permian Basin. The industry has spent the last decade or so developing its best rock, and the reality is that premium locations are not infinite. As that inventory tightens across the basin, the strategic value of companies that still hold significant high-return drilling inventory will only increase. Our responsibility is to develop those locations with discipline, maximizing the long-term value for our shareholders. When we think about the value of this company, several key components stand out. First, our existing production base, a highly visible, reliable source of cash flow that underpins the business today; and at current valuation levels, HighPeak Energy, Inc. is trading close to the PV-10 proved-developed value. But the real long-term value lies with the untapped inventory. That inventory includes approximately 200 proved undeveloped locations in our core zones, more than 400 additional premium Wolfcamp A and Lower Spraberry locations, over 200 Middle Spraberry locations progressing toward the sub-$50 breakeven delineation, and further upside potential in the Wolfcamp B, C, and D zones. All of this is complemented by our continued focus on optimizing existing production, which enhances returns and strengthens the value of our asset base over time. In closing, our focus in 2026 is on returns and resilience, not headline growth. We will apply strict capital and operational discipline to protect the bottom line. We will prioritize free cash flow generation. Any incremental free cash flow will first be directed toward reducing leverage and strengthening the balance sheet, positioning us for a lower cost of capital over time. We will remain precise and selective in how we deploy capital, concentrating on high-return inventory, base production optimization, and disciplined delineation of additional premium locations. At our current development pace, our premium inventory alone represents decades of high-return drilling, even before accounting for the additional upside we can continue to delineate across our acreage. And as tier one shale inventory becomes increasingly scarce across the industry, the strategic value of remaining core drilling locations will only continue to rise. Ultimately, we are building a company designed to generate strong returns across commodity cycles, improve long-term NAV realization, and strengthen our equity value. And it all starts with reinforcing our financial foundation. Before I close, I want to recognize our employees. The progress we have discussed today is a direct result of their hard work, grit, and professionalism. Day after day, they show up, tackle challenges, and keep this company moving forward. Their commitment, both in the field and in the office, is the backbone of everything we are building. Again, I am deeply grateful for what they do. With my comments now complete, operator, please open the call up for questions.

Thank you. Ladies and gentlemen, if you have a question or a comment at this time, please press *11 on your telephone. If your question has been answered and you wish to remove yourself from the queue, please press *11 again. Our first question comes from Noah Hungness with Bank of America. Your line is open.

Yeah. I just wanted to start off here, Mike, if you could add any more color on some of your cost reduction and production optimization efforts that you have implemented over the last six months?

You bet, Noah. Thank you for the question. Obviously, it is what we do every day, so it is not like this was an initiative started, you know, a quarter ago. But to kind of walk through some of the cost reductions that we have seen both on the capital side and on the expense side. We have done a lot of optimization on how we are drilling and completing these wells. Obviously, we get a little faster every day—drilling, a little faster completions. We have also optimized the completion chemical program, the perforation schemes, how we are landing these wells, as well as kind of structural changes to how we complete these wells like utilizing final frac today versus what we were doing in the first part of 2025. So there is a lot on the capital side being more. On the expense side, we are doing a lot of production base production optimization. So think lowering pumps, changing the type of artificial lift that we utilize, utilizing some chemical opportunities that we have for, you hate to say, restimulation, but being able to pump some things downhole that can increase production and, what—yeah—your return from the wells, as well as remove some of what they call skin damage that allows more of the fluid to flow into the well. So we have a program ongoing doing that. And overall, we have had lower commodity prices over the last couple quarters which, you know, again, not that we do not do this every day, but we constantly rebid, reevaluate, look structurally at what we are doing with our infrastructure, how we treat the wells chemically, and go out for bids very routinely. So we are seeing some cost savings on that front. Not just how we are drilling the wells, but just the unit pieces that go into it and staying on top of that and making sure we are getting the best price for HighPeak Energy, Inc.

That is helpful. And then for my second question, could you maybe help us think about the split of TILs across your development area for 2026? So what does the split for, you know, Lower Spraberry versus Wolfcamp A versus Middle Spraberry look like? And then also, the different development areas that you have helped highlight this quarter, so, you know, North Borden versus your core Flat Top versus your core Signal—if you could just give us any color there.

You bet. So the good news is what we are drilling for the foreseeable future will look almost identical to what we have done for the last year and a half. Right? It is about 70% of the capital will be spent in Flat Top, the northern block. And, again, that happens to be about the acreage split between the blocks, Flat Top and Signal Peak. So 30% give or take of the capital in Signal Peak. Think 90+% of that capital will be Wolfcamp A/Lower Spraberry co-development. The other 5% to 8% of capital will be Middle Spraberry, and some of the Middle Spraberrys will be co-developed with the Lower Spraberrys as well, but it will be in the Middle Spraberry, not in just the A and Lower Spraberry. Now the split between, you know, again, in the Northern Borden versus Flat Top Core—almost 50/50 for the Flat Top area. That 70% will be almost 50/50 between North Borden and Flat Top Central, I guess you would call it. One point to make is, as I said in the prepared remarks, we will not drill any wells like we did in 2025 in that little red box that is on slide 6 of our presentation; there will be no drilling in that area in 2026.

And so you are TILing a few more wells than you are drilling this year. Can we assume that the percentages you talked about on the drills are going to be pretty similar to the TILs this year?

Absolutely. Because it was basically the same percentage of drills last year. So those TILs go into 2026. And you make a great point. We are completing, you know, call it roughly seven more wells than we are drilling this year. We brought into 2026 something close to 20+ wells, called, you know, operational DUCs. And then if you kind of math out where we will be at the end of the year, we should carry out into 2027 roughly 14 to 15 DUCs, again setting us up very nicely in 2027 to be able to effectuate exactly the same plan that we have in 2026, again, for further strong reduction in absolute debt.

That is helpful color. Thank you.

Yes, sir. Thank you.

One moment for our next question. Our next question comes from Jeff Robertson with WaterTower Research. Your line is open.

Thank you. Good morning. Mike, on slides 10 and 11, you show the production profile and CapEx and the capital intensity. Can you talk a little bit about where the company’s corporate decline curve was at the 2026 and where you think it might be at the ’26 end, and how that plays into the notion of increasing capital efficiency over time and delevering the balance sheet in ’26 and ’27?

You bet, Jeff, and thank you for that question. I may step back a couple of years prior to that instead of starting just on, you know, ’25 and ’26. It is really important. Again, building a company from absolute greenfield all through the drill bit, and building up to close to 50,000 BOEs a day, we had to drill a lot of new wells with several rigs. So if you go all the way back to kind of the exit of 2024, corporate decline rate was, call it, mid-40%. So, again, pretty steep because you have a lot of new wells. At the end of 2025, we were down to about 38% corporate because, if you recall, we had slowed down at the, you know, kind of midpoint of ’24 and into ’25. We slowed way down. And then even midpoint of ’25, we went down to one rig. So as you look forward into 2026, of course, you came into the year right at 38%. At our current cadence and what we will continue to do for at least the foreseeable future, you can expect about 2% decline in corporate decline rate. So the 38% we came into the year with, we should exit the year into 2027 at, you know, 36% or so. And to your point, as your corporate decline goes down, the amount of CapEx needed for maintenance CapEx to hold your production flat also comes down by that kind of relation.

Does HighPeak Energy, Inc.’s amortization on the term loan start again in the third quarter? I think it is about $120 million a year. So if you were to be—if, let’s just say, over the next four quarters beginning this year, $120 million a year is roughly $1 a share, based on 125 million shares outstanding. Are you trying to position the company where you could accelerate the amortization of the term loan?

Absolutely. So, Jeff, and the great thing is the amortization is a set rate, right? It is $30 million a quarter. The great thing about where we sit with the term loan is that we have the ability to pay down any amount on the term loan at par. So to your point, we can take any additional free cash flow that we are generating with this capital-efficient program in 2026, in the backdrop of commodity prices being higher today. And, you know, I think it is a little—literally me. Right? We are geared very heavily to oil price. And as you mentioned, where else could you find in the public world where you have such a high gearing to the debt level that we have? To your point, in this environment, we will be able to pay down debt at a much accelerated rate, and for every $125 million we pay down, as you absolutely said correct, it should be roughly $1 per share. And in today’s price environment, that is close to a 20% increase in market value. By doing exactly the same thing in the next year, you should have similar results except you pay down more debt and there is kind of a snowball effect because we do have a high cost of capital, call it 10+% interest, and it would be reasonable to assume that later down the road, once we get the financial house in order by staying very disciplined, we will have opportunities to hopefully lower that cost of capital going into the future.

Thanks. And so, lastly, on operations, Mike, is there anything structurally with respect to, say, water handling or anything else in the field that you are working on in 2026 that might offset some of the production optimization spending that you outlined?

So, you know, the good thing is anything we do to optimize production increases the revenue that we have in, lowers all of the per-BOE metrics that we have. Now, on the water system, the great thing is the water system is there. It is paid for. It has been there for a while. We just utilize what we already have, which makes both on the capital side for recycled water for stimulations, as well as disposal of any of the produced fluids, very, very efficient. And when you look at the capital reduction or what we like to call the intensity of capital needed to produce a certain level of volumes of hydrocarbons, it continues to go down over the last couple years. If you go all the way back to 2023, HighPeak Energy, Inc. spent $1 billion. In 2025, it was, you know, call it $500 million. 2026, half that number. Now, I do not want anyone to think 2027 is going to be half of 2026. It will be slightly lower because we do have some infrastructure that we have planned and in the budget in 2026 that is not going to happen in 2027. So think $15–20 million cheaper total CapEx in ’27 to effectuate the exact plan that we have for ’26. The company will continue to get more efficient. And as you laid out earlier with the corporate decline dropping each year, that also helps accelerate that corporate efficiency.

Thank you.

Yes, sir. Thank you.

Once again, ladies and gentlemen, if you have a question or a comment at this time, please press *11 on your telephone. And I am not showing any further—actually, one moment. We have a follow-up question from Jeff Robertson with WaterTower Research.

Perfect. You ready for one?

One question that came up on the November conference call was the distribution of shares by the HighPeak entities. Is there any update you can provide on the planned distributions in 2026 and 2027?

Yeah. Good morning, Jeff. Good question. When we rolled into the 2026 calendar year and oil prices were kind of in the mid to upper $50s at the time, we got with the majority investors in the partnership and ended up extending for an additional year, which will allow us to get into, hopefully, a healthier market environment for fund distribution timing. We do have the flexibility to do it throughout the calendar year, or we could kind of go all the way through 2026 and start the distribution in early 2027.

Okay. Thank you.

You bet.

And I am not showing any further questions at this time. As such, this does conclude today’s presentation. We thank you for your participation. You may now disconnect, and have a wonderful day.