HighPeak Energy Inc Aktie

Good day, and thank you for standing by. Welcome to HighPeak Energy's 2026 First Quarter Earnings Call. [Operator Instructions] 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.

Thank you. Good morning, everyone, and welcome to HighPeak Energy's First Quarter 2026 Earnings Call. Representing HighPeak today are President and CEO, Michael Hollis; Executive Vice President, Ryan Hightower; Executive Vice President, Daniel Silver; Senior Vice President, Chris Mundy; and I'm 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.

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 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.

And I'll tell you right up front, the business is doing exactly what we said it would do. We are executing, we're staying disciplined, and we're building a stronger company quarter-by-quarter. Let's start with the first quarter.

We're off to a very strong start this year, and I'm proud of the way our team has performed across the board. We outperformed expectations on every major operational metric. Production averaged approximately 46,000 BOEs per day, which came in about 7.5% above the midpoint of our guidance range, which includes the effects of Winter Storm Fern. And with quarter-to-date production coming in as strong as or stronger than Q1 production.

Now oil production specifically was up 10% quarter-over-quarter, which is a meaningful step-up and speaks to the quality of both our new wells and our base production. And that's important because it wasn't driven by just one thing. It was a balanced success.

We saw strong performance from the new wells we brought on during the quarter. And at the same time, we continue to optimize and improve our base production. That combination is what drives consistency in the business. It's a direct result of the operational work our team has been focused on over the last several quarters, dialing in execution, tightening processes and getting better in every aspect of the business.

Now let's talk about costs because this is where we really separated ourselves this quarter. Our operations team delivered exceptional cost performance. Lease operating expense per BOE came in more than 17% below our guided range and roughly 22% below the fourth quarter levels. That's a material improvement in a very short period of time.

And just as important, it wasn't just a per unit story. On an absolute dollar basis, our operating costs declined by approximately $7.4 million quarter-over-quarter. So we spent meaningfully less money while producing more barrels. That's exactly what operational efficiency should look like.

Now what drove that? Three primary areas. First, continued optimization of our chemical program, making sure we're using the right treatments in the right places at the right cost.

Second, more efficient use of field gas. Given the current dislocation between Waha pricing and Henry Hub, we're not making money on our gas at the moment. So, we're putting it to work in our own operations wherever we can. That's a practical economic decision and is paying off.

And third, continued electrification across our field operations. That's improving reliability, lowering costs and positioning us well for the long term. Now put it all together, this is a structurally more efficient business than it was just a few quarters ago.

Turning to our development program. We are exactly where we need to be. First quarter drilling and turn-in-line activity represents roughly 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. Now as a reminder, we've guided to deploying roughly 60% of our capital in the first half of the year, and we remain firmly on track with that plan. Execution is steady, predictable and controlled.

Now let's step back and talk about the bigger picture, capital discipline and efficiency because that's really the core of our strategy. As you know, we made a deliberate shift heading into 2026. We reduced our capital program by roughly 50% compared to last year. And we moved into what we are calling maintenance mode development strategy. And the goal is simple, hold production roughly flat while maximizing free cash flow. And the early results are very encouraging.

One key metric we track is net oil produced per dollar of capital invested. Quarter-over-quarter, that metric improved by more than 60%, moving from about 21,500 barrels per million of capital spent to approximately 35,400 barrels per million. That's a significant step change in efficiency. And again, it's coming from both sides of the business. Strong well performance on new capital and meaningful gains on the base asset.

Now let me spend a minute on that base optimization work because it's an important part of the story. During the quarter, we executed 16 targeted workover projects. These projects increased production from roughly 1,600 barrels of oil per day to about 2,600 barrels of oil per day. That's an add of about 1,000 barrels of oil per day, 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. But when we look at the market and more importantly, when we make decisions, we focus on the back end of the curve. And what we've seen there is a much more modest move, roughly a $10 to $12 increase from around $60 a barrel at the beginning of the year to the low $70s per barrel currently.

Now that's constructive, but it's not something that fundamentally changes our strategy. We are not going to chase short-term price signals. We're not going to accelerate activity just because spot pricing has moved. We are going to stay disciplined and develop this asset at the right pace. And that's one that reflects sustainable pricing, capital efficiency and long-term value creation.

Now with that said, this geopolitical situation, if it persists, we do believe there will be increasing pressure on the back end of the curve over time. And if that happens, it creates a meaningful long-term opportunity for HighPeak. More sustained pricing strength means higher incremental free cash flow for years to come and that's where real value gets created.

And importantly, we are positioned to benefit from that environment. We currently have approximately 40% average exposure to spot oil prices based on the midpoint of our production guided range and our current hedge book. Please note that current production is well above this level and giving even more exposure. That gives us meaningful upside to stronger pricing. And at the same time, we've protected the downside.

We've established a hedge floor in the mid-$60 per barrel range that provides a reliable base level of cash flow to fund our development program and service our debt. So, we've got both upside torque and downside protection, and you saw that show up in the first quarter.

Excluding changes in working capital, we generated over $21 million of free cash flow. That's up from a negative $42 million last quarter, and that only reflects less than one month of elevated oil prices. If prices remain higher for longer, that free cash flow number moves up materially as we move through the year and accelerates the time frame needed to strengthen our balance sheet. Again, our priority for that free cash flow is very clear. We are going to strengthen the balance sheet.

One additional item to touch on as we talk about strengthening the balance sheet, we recently put on an at-the-market or ATM program in place. This gives us the ability to issue up to $150 million of common stock.

Now just to be clear, there is no requirement for us to issue a single share under this program. This is about flexibility. It's a tool that allows us to be opportunistic if we see dislocations in the market. And if we do choose to access the ATM, the use of proceeds is very straightforward. It's about reducing debt, increasing liquidity and continuing to strengthen the balance sheet.

Now let me close with our focus for the year. Look, nothing has changed, and that's by design. Our priorities are clear. First, strengthen the balance sheet through sustained free cash flow generation, debt reduction and/or increasing liquidity. Second, preserve high-quality inventory by developing our inventory at a disciplined pace and continuing to optimize both new wells and our base production. Third, improve corporate efficiency, focusing on returns, not volumes and ultimately create long-term equity value and maximize net asset value.

We are allocating capital where it drives the highest returns, and we are building a more durable, more resilient business that is built to thrive across commodity cycles. Now stronger commodity prices are helpful, no question. But disciplined execution is what creates long-term value, and that's exactly what HighPeak is delivering.

With my comments now complete, operator, please open the call up for questions. Or some technical difficult there.

[Operator Instructions] Our first question today comes from Jeff Robertson with Water Tower Research.

Mike, given where you are with production and 60% of estimated '26 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 '26, any early color or preliminary color on 2027?

No, Jeff, great question. And as we laid out in our guidance last quarter, we were planning to spend roughly 60% of that budget in the first half of the year. And as we've 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 spend for the year. So as you look through 2026, the activity in Q2 will be very similar to what we had in Q1.

From a production standpoint, yes, we're running hot to our guide today and up through quarter-to-date even. And as you look through the latter half of the year, the additional work that we do in the first half, that is the wells that are going to be producing in the second half of the year. So I think what you'll see throughout 2026 is more of a flat production profile that looks very similar to what we've done to date this year.

And again, yes, it's a little hot to our guided range on the top -- above the top end of the guided range. And we hope between base optimization projects that we're working on and the great performance we've had from our new wells, and we're drilling very similar wells throughout the entire year, and that's what's going to be coming online that we will be in the upper portion of that production range that we guided to originally. But for the CapEx spend, the guided range is still very applicable, and I think we've 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 were detailed enough to make a brick as I like to call it from West Texas slang. But I think if you look into 2027, I would assume a very, very similar program to what we had in 2026. And there was one question I did not answer, which was how many DUCs we would exit the year at. We will exit with roughly nine to 10 DUCs in 2026 going into '27. So, we would be set up very similarly to do the exact program that we have in '26 and '27.

So again, if you're looking at kind of a CapEx spend in '27, I think what we have this year at the midpoint of about $270 million is where you need to be 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 results in the increased production that you highlighted on Slide 7.

No, that's a great question. And Jeff, we've got upwards to getting now close to 400 horizontal wells that are producing. So, as we go through all of our inventory of producing wells, we do have a list of wells that we think would be -- would benefit from this type of intervention more than others. However, if a well is producing fine and everything is 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 want to do too many at one time. We're pretty early in this process. So what we've done to date are wells that we were going to go touch and do work on for some reason or another, and they met the requirements and look like a good candidate. Those are the ones that we went and did. And I think that's how you can kind of assume we will do for this year, maybe even next year.

We need more time to watch the production increase that we have from these interventions and how that plays out over kind of a year, two-year time frame to really understand that before we would want to go and attack a well that's currently producing. And these are well interventions that we were going to have to do something, think of -- I'd like to call it a mini stimulation on the well, think surfactants, acid, more or less cleaning the wellbore out and reducing damage to the formation that happened over time. And we're seeing really good results.

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

Brian 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?

Yes. 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. So, 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 final frac jobs kind of working its way through the system. All that's behind us now. So, on a go-forward basis, it's more steady state. So, I wouldn't expect those large capital -- working capital swings on a go-forward basis throughout the rest of the year.

And just lastly, Brian 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?

Yes, absolutely, Jeff. And I think you're referring to a large hedge loss in the first quarter. So, the way to think about it, total derivatives loss in the first quarter on paper was about $55 million. Only $17.4 million of that was actual cash loss. The rest of it, roughly $140 million, was a mark-to-market loss that was done as of March 31.

So the way to think about that, if prices kind of pull back to lower levels throughout the rest of the year, that mark-to-market loss is going to shrink and any potential cash hedge loss would shrink as well as we kind of progress throughout the year.

Our next question is from Nicholas Pope with ROTH Capital.

Curious to dig a little bit more on the workovers. I know you have this slide kind of talking about the benefits of that. It looks like the workover expense for the quarter was actually pretty low relative to kind of what the run rate was in 2025. And so just trying to understand, I guess, what the activity expectation is going forward?

I mean a lot of wells, obviously, that you're looking at to potentially augment with improved productivity with these workovers. But kind of looking at this expense line items, 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 I'm trying to understand how that splits out. 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. So let me step back to last year. And to kind of answer the question as to why overall LOE is down and LOE is kind of two buckets, right? It's your typical and day-to-day everyday LOE and then it's your workover expense. And think workover expense is repairing something on a well and just getting it back to the same kind of state that it was. That's the workover expense.

If you look back in the 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, and we spent, call it, $1-ish or a little bit more per BOE doing that in 2025.

We only have so many wells, and there's always going to be some workover expense, make sure you don't read through that it's going to zero. But I think a reasonable run rate for workover expense, probably somewhere in the $0.75 to $1 range is extremely conservative. Obviously, we are much lower than that in Q1.

Now to answer your other question about the type of interventions, again, we touch a lot of wells all the time. Some are designated as expense work, basically getting the well back to its original state. Some are considered capital workovers where you're adding reserves and changing the value of the well after the fact.

So, to that, I would say, with all the work we did throughout the quarter, some of these were capital workovers and are in our capital spend for the quarter. And I think that screened very well for the amount of work we did on our D&C budget. The read-through there is we're shaving cost where we can on our traditional D&C budget enough that we're going to be able to slide some of these capital workovers in within the budget we currently have.

And on the expense side, again, we wanted to be very conservative with our early guide range. That's why you saw a fairly sizable workover program because we wanted to say, "Hey, we had to continue what we did in '25," this gives us plenty of money in the budget to do it. But I think you're looking at it exactly right. It's not like we just moved a lot of costs from the expense bucket to the capital bucket or you would have seen it show up there. Overall, total cost is coming down.

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 -- I guess, second half of last year, 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, are we just -- 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. A quarter or so ago, we had a slide that showed a red box right exactly where you're talking about. And yes, we encountered some extraneous water production in that area. We kind of talked about the impact it had on our inventory. So the only zone we carried inventory in that little red box was Wolfcamp A. And 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.

Now the existing wells that we do have there, we've got three of those wells producing today. We've done some interventions on those wells to reduce the amount of water coming in. So, they are very economic. They're just lower production because you're only producing from, call it, 4,000 feet of actual producing rock out of those wells.

So from an economic standpoint for a new well, no, we would not drill another one. But we will optimize the wells that we do have in that area. But absolutely, that had an effect with production kind of in the second half of 2025. And again, all of that kind of rolls through on a BOE basis for your LOE per BOE cost in the second half of the year as well.

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

Yes. No, Great question. And again, we constantly highlight the infrastructure that HighPeak has put in place over the last five-plus years. And to your question there on the water system, if you look back a couple of years, we were running six rigs, three frac crews and looking to build to 75,000 to 100,000 barrels of oil a day.

Now with that, you need to be able to handle 400,000 barrels of water per day. So we put in very large pipes, very large pumps, several SWDs. So our SWD capacity is a little over 400,000 barrels of capacity today. Pipelines that are 24 inches in diameter, we can move around 400,000 barrels a day. And of course, we recycle almost 95% of what we use on the stimulation side.

But to give you an idea of where we sit today, we're producing roughly -- on a gross basis of oil that we produce, it's pretty close to 45,000 to 47,000 barrel gross of oil. So with that kind of 4:1, we're a little over 200 -- call it, 210,000, 220,000 barrels of water a day being produced across HighPeak. Some of that -- a little bit more than 4x is because you have some flowback from the new frac wells.

But we're about 45% to 50% utilized of capacity that HighPeak has. We take very little third-party water into our system. It's available. So for folks near and around us, we do have plenty of capacity for disposal. But the infrastructure was built for life of field and that stretches across our oil, gas, electrical recycle capability, all of that's built in place.

And I think you're seeing that on our LOE cost numbers. And then same thing on our CapEx numbers as we have built our -- all of our large central tank batteries, you're starting to see the cost per well go way down because today, when we drill a new well, -- all we have to do is add some metering equipment to tie it into an existing battery that's already there. So, both sides of the equation is what we've attacked, and we've been able to bring costs down across the board.

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 2025 Fourth Quarter Earnings Conference Call. [Operator Instructions]. Please be advised today's conference is being recorded. I would now like to hand the conference over to your speaker today, Steven Tholen, CFO. Please go ahead.

Good morning, everyone, and welcome to HighPeak Energy's earnings call. Representing HighPeak today are President and CEO, Michael Hollis; Executive Vice President, Ryan Hightower; Executive Vice President, Daniel Silver; Senior Vice President, Chris Munday, and I am Steven 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'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 March 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. 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'm far more energized by what lies ahead than by revisiting what's 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's turn the page and talk about 2026. and how we're 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. And 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're taking several decisive steps.

First, we rightsized 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 wasn't 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 of quarters, but for years to come.

Our 2026 development plan is intentionally conservative and built for durability. It is anchored around 1 drilling rig and roughly 1 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 Fern. 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 '26 budget and our plans to reduce absolute debt.

Stepping back, it's 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 1 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 1 inventory for a future time when our financial capacity and a strong sustained commodity environment align. So 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 cushion 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 stronger. 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've 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 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's 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's drilling a new well, optimizing existing production, reducing debt or pursuing strategic opportunities. We will preserve premium inventory. Tier 1 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 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 isn't to grow the fastest. Growth should be the outcome of a well-executed financially solid plan. This does not happen overnight. HighPeak'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's 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 reinforce the quality and consistency of this acreage. The Northern-most rove 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.

Now the Northeast Flat Top area, highlighted by the small red box, also on Slide 6 of our March investor deck, shows where 6 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're also seeing encouraging progress in delineating the Middle Spraberry across both HighPeak and our offset operators. There are now 9 successful producers, and we expect that momentum to continue with roughly 6 additional delineation wells planned between HighPeak and offset operators in the first half of 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've demonstrated Wolfcamp B 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's not going anywhere. We haven't drilled a Wolfcamp D well in roughly 3 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 overtime. 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 has more than 2,600 total drilling locations across the stack, 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 from most of our peers.

One point that we believe the market continues to under-appreciate is the growing scarcity of Tier 1 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 standout.

First, our existing production base, a highly visible, reliable source of cash flow that underpins the business today and at current valuation levels, HighPeak 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 continue to delineate across our acreage, and as Tier 1 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've 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're building. Again, I'm deeply grateful for what they do. With my comments now complete, operator, please open the call up for questions.

[Operator Instructions] Our first question comes from Noah Hungness with Bank of America.

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've implemented over the last 6 months?

You bet. Noah. Thank you for the question. Obviously, it's what we do every day. So it's not like this was an initiative started a quarter ago. But to kind of walk through some of the cost reductions that we've seen both on the capital side and on the expense side. So we've done a lot of optimization on how we are drilling and completing these wells. Obviously, we get a little faster everyday drilling, a little faster completions. We've 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 simul-frac today versus what we were doing in the first part of 2025. So there's a lot on the capital side being worked.

On the expense side, we're 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 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've had lower commodity prices over the last couple of quarters, which, again, not that we don't do this every day, but we constantly rebid, reevaluate, look structurally at what we're doing with our infrastructure, how we treat the wells chemically and go out for bids very routinely. So we're seeing some cost savings on that front, not just how we're drilling the wells, but just the unit pieces that go into it and staying on top of that and making sure we're getting the best price for high fee.

That's helpful color. And then for my second question, could you maybe help us think about the split of TILs across your development area for '26? So what is the split for Lower Spraberry versus Wolfcamp A versus Middle Spraberry look like? And then also the different area -- development areas that you've helped to highlight this quarter. So North Borden versus your core Flat Top versus your core Signal Peak. 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've done for the last 1.5 years, right? It's 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 between Flat Top and Signal Peak. So 30%, give or take, of the capital in Signal Peak, think 90-plus percent 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 Spraberry will be codeveloped with A and Lower Spraberry as well, but it will be in the Middle Spraberry, not in just the A and Lower Spraberry.

Now the split between -- 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'd call it. One point to make, as I said in the prepared remarks, we will not drill any wells like we did in 2025, in that little red box that's on Slide 6 of our presentation, there will be no drilling in that area in 2026.

And you're tilling a few more wells than you're drilling this year. Can we assume that the percentages you talked about on the drills is 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, call it -- roughly 7 more wells than we're drilling this year. We brought into 2026 something close to 20-plus wells called operational DUCs. And then if you kind of math-out where we'll 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.

Our next question comes from Jeff Robertson with Water Tower Research.

Mike, on Slide 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 beginning of 2026 and where you think it might be at the end of '26 and how that plays into the notion of increasing capital efficiency over time and de-levering 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 '25 and '26 because it's 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, a pretty steep because you have a lot of new wells.

At the end of 2025, we were down to about 38% corporate decline because if you recall, we had slowed down at the kind of midpoint of '24 and into '25, we slowed way down. And then even midpoint of '25, we went down to 1 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 assume 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 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's amortization on the term loan starts again in the third quarter. I think it's about $120 million a year. So if you were to be, let's just say, over the next 4 quarters, beginning late this year, $120 million a year is roughly $1 a share, with -- 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, the great thing is the amortization is a set rate, right? It's $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're generating with this capitally efficient program in 2026 in the backdrop of commodity prices being higher today. And I think it's literally me, right? We're 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's close to 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's kind of a snowball effect because we do have a high cost of capital, call it, 10-plus percent 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.

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

So there's -- 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's paid for. It's 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 continue to go down over the last couple of years.

If you go all the way back to 2023, HighPeak spent $1 billion. 2025 it was, call it, $500 million. 2026, half that number. Now I don't 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's not going to happen in 2027. So think $15 million, $20 million cheaper total CapEx in '27 to effectuate the exact plan that we have for '26. So 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.

[Operator Instructions] We have a follow-up question from Jeff Robertson with Water Tower Research.

Ryan, 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?

Yes. 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.

[Operator Instructions] And I'm not showing any further questions at this time. So as such, this does conclude today's presentation. We thank you for your participation. You may now disconnect, and have a wonderful day.

Good day, and thank you for standing by. Welcome to the HighPeak Energy Third Quarter 2025 Earnings Conference Call. [Operator Instructions]

Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Steven Tholen, Chief Financial Officer. Please go ahead.

Good morning, everyone, and welcome to HighPeak Energy's Third Quarter 2025 Earnings Call. Representing HighPeak today are President and CEO, Michael Hollis; Executive Vice President, Ryan Hightower; Executive Vice President, Daniel Silver; Senior Vice President, Chris Munday; and I am Steven Tholen, the Chief Financial Officer.

During today's call, we may refer to our November investor presentation and our third 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 November 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 today for HighPeak's third quarter conference call. I'm going to start today's call with a brief overview of our third quarter results and a quick update of our current development activity, after which and more importantly, I want to use this opportunity to give you a glimpse into our company road map looking forward. With that said, before we start talking about HighPeak's future, I'm proud to report that we delivered a solid third quarter results, which tracked our internal expectations.

Production levels were consistent with the second quarter despite our reduced level of development activity. We only ran 1 rig through the entirety of the third quarter, drilled 6 wells and turned in line only 9 wells. That's roughly 2/3 of our tills that we had in Q1 and Q2. Our CapEx was down 30% from Q2 as a result of our deliberate reduction of development activity and was spot on with our internal estimates. We held our LOE per BOE consistent with our first half 2025 levels. And as we discussed on last quarter's call, we successfully amended and extended our term loan, pushed out debt maturities until 2028 and materially increased our liquidity.

Now turning to current operations. Due to continued weakness in commodity prices and overall market volatility, we delayed picking our second rig back up until mid-October, a roughly 1.5-month delay from our original plan. Now we plan to run both rigs throughout the fourth quarter before making a determination as to what the appropriate level of activity should be for 2026, which will be heavily dependent on oil prices, D&C cost and overall market conditions. And we recently finished our second successful simul-frac completion on a 6-well pad with 15,000-foot average lateral lengths. This operation went smoothly with HighPeak recognizing cost savings per well of over $400,000 compared with our traditional zipper frac technique, and we were even able to increase some efficiencies compared to our first simul-frac job, more lateral footage completed per day.

We utilize continuous pumping operations and averaged over 4,700 feet of completed lateral footage per day. The operations team keeps delivering. We are very encouraged by the results that we've achieved to date utilizing the simul-frac ops, and we plan to tailor our 2026 development program to incorporate this completion technique more. Suffice it to say, HighPeak's operations and well performance are a well-oiled machine. That said, we will always find new innovative optimization opportunities. As we have always done, our operations department will maintain a laser focus on low-cost operations.

Now let's turn our focus to the future. I know you've all have heard from me and the other HighPeak senior team members on these calls in the past, but this is the first time I've had a chance to speak with you as the CEO, and I will very clearly lay out our vision for HighPeak moving forward. With our new Chairman of the Board and the entire team pulling in the same direction, we are moving forward with purpose and a sense of urgency. We're getting back to the basics, running a tight, disciplined operation built on focus, efficiency and sound business sense. Our assets are strong, our people are capable and our commitment to managing cash flow and capital is steadfast.

Now I won't sugarcoat it. Our debt is high, and the market has told us exactly what it thinks about that. For a while, we drifted without a clear long-term plan, and it showed. That changes now. We're rolling up our sleeves to strengthen the balance sheet and rebuild the trust the only way that works through steady, consistent results. We know talk doesn't cut it in this business, results do, and we will deliver. Now the first step in figuring out where you're heading is being very honest about where you stand and how you got there. Now we've done a lot of things right, and I want to tip my hat to the team for the hard work and follow through, but we also have some issues we need to face head on, no sense pretending otherwise. At the end of the day, the management, the Board and every one of us at HighPeak own the results we have delivered to date, the good, the bad and everything in between. It's ours to fix and to build upon.

So let's reflect on what we have done well over the past 5 years and also what needs improvement. You can refer to Page 6 of our investor presentation. So what have we done right over the past 5 years? Well, we've assembled a high-quality asset base in one of the most desired basins in the world composed of 2 highly contiguous acreage positions with oil-rich inventory, allowing for cost-effective extended lateral development and strong IRRs. We've done a great job operationally, maximizing efficiencies and developing a lean cost structure to drive enhanced economics. I would put our operational efficiency against any public company in the E&P space. We've also delineated a long runway of highly economic multi-bench oily inventory that is primed for full-scale capital-efficient development. These are all great attributes, and I want to commend the HighPeak employees, management and even our investors for believing in the team in this area.

But now let's look at some areas where we have misstepped and now need to improve. We are a controlled company, which has led to poor governance quality scores and high risk potential from the likes of ISS, Glass Lewis and some notable rating agencies. At times, we had a growth at all cost mentality even in the face of commodity price weakness. This ends now. This last view of cash management led us to overusing leverage and resulted in high cost of capital.

Finally, what we've heard loud and clear from our investors is that our short-term focus on the business has eroded market confidence. We own these weaknesses, plain and simple, and we have a plan to set them right. So what does that look like? Well, some of these fixes we can tackle right now, and we've already started. Others are going to take a little time and patience. This isn't something that happens overnight. We see it like climbing a set of stairs, one solid step leads to the next. The first one is already behind us. We have reset our governance and put the right structure in place. That gives us the footing to run this company the correct way with discipline, accountability and good old-fashioned business sense. We're not trying to reinvent the wheel here. Our focus is simple: Generate steady, sustainable cash flow; pay down our debt the smart way and keep our financial house in order. Lucky for us, we've got a solid asset base that gives us the horsepower to get it done.

And as we follow through step by step, I believe we will earn back the market's confidence the right way by doing exactly what we said we would do and sticking to our long-term plan.

Now let's talk a little bit more about each of these areas needing improvement. If you take a step back and look at any public company, there are 3 levels of control. First, you have the Board of Directors providing direction and oversight. Second, you have management team directing the day-to-day operations. And finally, you have the shareholders who bring accountability and real-time feedback to the organization. Previously, all 3 of these control groups were effectively consolidated or led by a single individual. Again, this has led to poor governance scores by proxy advisory firms and credit agencies. However, over the last few months, we have made key changes in each of these areas.

First, as most of you know, we've had a change at the top. Effective immediately, I have accepted the role of permanent President and CEO of HighPeak Energy. And I've got to say I'm proud of how this team has stepped up. Several folks in senior management have really grabbed the reins and leaned into the vision. It's been all hands on deck, and I couldn't ask for a stronger group to work alongside. We have made several changes to the senior management levels, and I want to congratulate several of these employees on their new roles and titles.

Second, we are pleased to welcome our new independent Chairman, Jason Edgeworth. It's been a genuine pleasure working alongside him. Jason brings strong leadership, clear perspective and a shared passion for the company's long-term success. I am confident with full alignment between the Board, management and shareholders; we will drive HighPeak forward with focus and alignment to shareholder value.

Third, unlike in recent past, we now have a fully independent Board committees in place consistent with best practices for noncontrolled companies. These include the Compensation Committee, the Nominating and Governance Committee and of course, the Audit Committee. This structure strengthens oversight and reinforces our commitment to transparency, accountability and integrity in everything we do. I want to emphasize again that both management and the board are completely aligned in our priorities. We share one clear goal, driving long-term success and sustainable value creation for HighPeak and its shareholders.

Now regarding the shareholders, there are some major changes planned. As you may know, HighPeak, the public company, is majority owned by 2 private equity partnerships, HighPeak Energy Partners I and HighPeak Energy Partners II. These 2 partnerships own and control over 75 million of our 125 million outstanding common shares. As was recently disclosed, these partnerships plan to begin methodically distributing shares over the next 2 years, with HighPeak II being distributed first in 2026 and HighPeak I in 2027. It is important to note, most of the limited partners have a long-term investment mindset. While we anticipate most of these shares will continue to be held by the limited partners, it will potentially provide an opportunity for some larger institutions and investors to be able to invest in HighPeak stock, which should assist our low float issue.

With all these changes, we plan to effectively split the 3 forms of control; management, the Board and the shareholder base into independent but fully aligned groups. Now continuing on the topic of accountability. Management will operate under clearly defined measurable goals, and our compensation will be directly tied to our performance against those objectives. We are in the process of finalizing our 2026 road map, which will outline these performance metrics and align our incentives with long-term value creation. You can expect this framework to be in place and active in early 2026.

Now let's talk a little more about sound business principles. As you know, commodity prices have a very direct effect on profitability. So despite improvements in operational efficiencies and cost structure, commodity prices are the single biggest factor in changes to our cash flow. So how are we going to navigate this volatile commodity market? In our slide deck, on Page 9, we have laid out a very simple yet common sense approach. And I want to point out that the oil price laid out on the slide are long-term pricing. Again, we are taking a long-term approach to capital discipline. All that to say, we will not have a knee-jerk reaction to very short-term swings in pricing. We will take a methodical and disciplined approach.

Let's start with the bear case scenario, which we are currently close to right now. In the event long-term oil prices are below $60 a barrel, our focus will be exclusively on operating within cash flow. This means on the CapEx front that we will be operating less than a 2-rig development program. This level of activity would lead to a moderate decline in overall production volumes, but this goes without saying there's absolutely no need to focus on growing production in an oversupplied or weak market. Again, we have a long-term view on value creation, and there is no reason to overdevelop or accelerate in drilling our high-value inventory in a low commodity price environment. Now as far as liquidity is concerned, in the face of sustained low oil price environment, anything is on the table. We will preserve liquidity.

Now moving to the base case scenario of long-term oil prices in the $60 to $70 a barrel range. Our focus will be on free cash flow generation and prudently paying down our debt. On the CapEx front, this would most likely equate to a 2-rig development program resulting in maintaining current production volumes. Now on the liquidity front, we would maintain our current dividend and use the additional free cash flow for a modest debt paydown strategy.

In a bull case scenario of $70-plus oil, our focus will still be on increased free cash flow generation and accelerated debt paydown. On the CapEx program, we would likely be 2 rigs or just slightly more, leading to moderate production growth. And on the liquidity front, it would allow us to accelerate debt paydown. But let me be clear, we would have to be in this bull case scenario for quite some time and reach a reasonable leverage ratio before we would ever consider additional shareholder value initiatives. We will get our financial house in order first. As I said earlier, these are basic business principles, but I wanted to lay them out in a very clear and concise manner. This will be the framework for our high-level road map for 2026 and beyond.

Now we have listened to our constituents, shareholders, creditors, rating agencies and peers in the industry. And we have compiled some of these comments that we've heard and hear often, and we've laid them out on Slide 10 of our company presentation. Now we're fully aware of the challenges in front of us from geographical positioning of our assets, to cost of capital, to questions surrounding the company's potential strategic options. Now the key question is how to begin to rebuild and sustain market confidence. We're not ignoring the realities of our situation. Instead, we're facing them head on. And I want to take a moment to address several of the most common concerns we often hear. I want to do that openly and directly.

Number one, Eastern Midland Basin is unproven. HighPeak has drilled over 350 horizontal wells and have produced over 90 million BOEs from those wells, and third-party organizations are now recognizing well performance, cost differences, i.e., profitability and inventory quality and scale. HighPeak's and offset operators' track records over the last several years have dispelled this comment.

Number two, you guys have a growth at all cost mentality. As I previously said, there were many times in our history that may have been the focus. But I think HighPeak has been consistent over the last couple of years in trying to maintain our current level of production and show the market that we are going to operate within cash flow.

Number three, HighPeak is overlevered. That is a true statement. We are overlevered for the size of company we are today, and this is one of our primary focuses moving forward. We are working to address this issue in a thoughtful and methodical way. Hopefully, you've gotten that sense through this call that operating within cash flow and paying down debt are absolutely top of our list and major areas of focus.

Number four, you're starting to have GOR issues as your percentage gas production is increasing. We have seen increases in gas and NGL production. However, this is primarily due to historical takeaway issues that have been solved. As our gas midstream partners increase their takeaway capacity, and we have connected all of our central tank batteries to our gathering system and our gatherers have lowered field-wide pressures, has allowed more oil and gas -- or more gas and liquids to flow to sales. I would also like to remind everybody that our percent oil production will fluctuate from quarter-to-quarter at times due to where our completion operations are taking place and the timing associated with turning online new pads. But at any reasonable cadence, our oil percentage should trend closer to 70%.

Number five, HighPeak has no float in their stock. Now I hear this one a lot. Typically, I own it in my personal account, but I can't own it in my fund. Now this has been a serious issue that we have faced for some time now, and we have done some things in the past that may have exacerbated the problem. However, we are working to fix this issue as it is extremely important moving forward. I've already discussed the methodical distribution plan for the 2 HighPeak partnerships. We are going to be measured and deliberate in how we solve this problem. It cannot be fixed overnight.

Number six, HighPeak has been for sale for years. HighPeak is a publicly traded company. And as such, we are always open to evaluating value-enhancing opportunities. That said, again, I want to be very clear, the Board and management are fully aligned and unwavering in our commitment to long-term strategy of operating within cash flow, exercising disciplined decision-making and maintaining measured controlled execution. Our focus remains on building sustainable value for our shareholders over the long term.

Final one, HighPeak is a controlled company, and there is no oversight. As I've highlighted earlier in the call today, we're very encouraged by the progress we've made over the last few months. We have established fully independent Board committees, appointed an independent chairman and put in place a clear plan starting in 2026 to transition away from being a controlled company. These steps strengthen oversight, enhance accountability and position HighPeak for long-term sustainable value creation.

Now in conclusion, our company is in the midst of a meaningful transformation, one centered on stronger governance and accountability and a long-term focus on creating value for our shareholders. We're allocating capital with discipline, managing costs with precision and maintaining relentless focus on efficiency. Our asset base gives us the flexibility to operate within cash flow, generate sustainable free cash, reduce debt and continue building value the right way. We are not in the business of chasing production for short-term gains. We are here to build a durable, well-run enterprise, one that applies sound business principles and puts every dollar to work where it drives the greatest return. Through disciplined execution, clear direction and a unified team; we're positioning this company to perform in any environment. We are proud of what we have built, confident in where we are headed and focused on delivering lasting value for our shareholders, employees and partners. Thank you.

And with my comments now complete, we'll open the call up for questions.

[Operator Instructions] Our first question comes from the line of Jeff Robertson with Water Tower Research.

Mike, can you talk in the context of your leverage plan, how you think that unfolds over 2026 under, say, your $65 scenario and how much flexibility that might give you or give the company to address the term loan?

Absolutely, Jeff. No, great question. Obviously, the free cash flow generation is going to be dictated mostly by the oil price that we garner from the market. HighPeak is doing all the things we can control from cost management to capital deployment. But again, as you've pointed out, in that kind of base case scenario, we can generate significant free cash flow. Our term loan debt that we have today, we can pay down debt at par with no penalty. So as we generate free cash flow in that scenario, look for us to do that again, which will reduce absolute debt as well as reduce our leverage ratio.

Now if you look further into the future, again, could be a year, could be more as we continue to delever the company and as we continue to progress and our production base ages, what you'll see is our corporate decline rate will come down, call it, 1.5% to 2% a year. Today, we sit kind of mid- to high 30% decline rate. That changes your credit profile and again, opens you up to potentially more normal way financing into the future. But again, Jeff, today and into the very near future, our goal is capital management and paying down debt.

How do hedges fit into those goals, Mike? I know you've got, I think, an average swap price on some of your production for '26 at about $63 a barrel.

Yes. And could you repeat that? Our speaker was cutting out a little bit there, Jeff, I'm sorry.

Sure. Just basically, how do you think about hedging in the context of managing cash flows in a $60, $65 per barrel price environment to work towards your leverage goals? I know you have some, I think, minimum requirements, but I'm just curious how you think about that as you go forward.

You bet. No, great question, Jeff. We want to be very -- what you will see from HighPeak is a much more systematic and methodical hedging program. Obviously, we do have some minimum requirements and we will continue to have to hedge a little bit into the future each quarter, but those are small pieces. Now we'll always be opportunistic if that opportunity were to come along. You'll notice that we layered on some gas hedges a couple of quarters back that were fantastic prices in the $4.43 range. We've also hedged some basis differentials. But I think what you'll see in the -- as prices continue to stay in this lower range, it will be very methodical and small slices that we will layer on. Again, you tend to see less when prices are low. And then when prices move up a little bit, I think you're going to see us layer on a little bit more. We want to protect our capital budget. We want to protect the dividend as it sits today, again, in this kind of base case $60 to $70 range.

But I think looking forward to think somewhere in the 55% to 65% hedged at these kind of prices are probably what you would see HighPeak move towards. Obviously, if we had a spike in commodity prices, you may see us push that above that hedge percentage going forward.

Our next question comes from the line of Noah Hungness with Bank of America.

Our next question comes from the line of Nicholas Pope with ROTH Capital.

Curious, as you kind of look at this plan and you look at the flex that you have with different -- at different oil kind of environments, you brought that second rig back. Curious if there's changes in how you're thinking about where kind of within the acreage footprint you're going to be drilling or what you're going to be drilling? And if the focus changes in those different scenarios, maybe between Flat Top, Single Peak or even in the different formations, like how much flexibility is there? And how much does the pricing affect what and where you're drilling these different scenarios?

No. Great question, Nick. The good thing is we're drilling Wolfcamp A, Lower Spraberry codeveloped. I think 5% to 10% that we will drill in the Middle Spraberry zone, whether we run 1.5 rigs or 2 rigs, that split will not change in what we drill. Now where we drill, if you look at the split of the capital deployment that we've had in the recent kind of year or so, it's about 70% up at Flat Top and 25%, 30% in Signal Peak. That also fits with what our inventory in each one of those zones are between Flat Top and Signal Peak. Returns are very similar between the 2 areas in all these zones. So again, we approach it as a co-development program and the split between Flat Top and Signal Peak is more based on the split of inventory, which is about 70-30.

Got it. That makes sense. As you kind of look at the base, I mean, the lease operating expenses have been, I mean, almost flat the last 6 quarters. I'm curious if there's opportunities for going back into wells, seeing an uptick in workovers, field maintenance type work as you're maybe shifting a little bit away from a more active drilling program, the field optimization kind of you talked about 350 wells that have been drilled in this Eastern extension of the Midland. Curious how that might change with kind of maybe a slower development program.

No. Great question, and we're ahead of you on that. So if you look at the last kind of 2 quarters, you'll see some expense workover spend that was a little higher than what it had been kind of Q1 of this year or Q4 of the previous year. So where we were normally running kind of $0.80 per BOE, somewhere in that range, we've been $1 or a little bit more in the last 2 quarters. So as we pulled back on that capital program, now there are some capital workovers that we have done as well, but think very, very high rate of return work. So we've gone into some of our wells and done some expense workovers and have seen some really good results from that. So again, while we've pulled back activity on the drilling complete side, we have gone back and optimized our production base. And we'll continue at a little bit lower pace going forward because we hit all of the large items that we had on our list in the last quarter or so. But there will be additional work every quarter that we will continue to focus on to keep that efficiency high.

And those expense workovers that you kind of highlighted, I know you break out somewhat, is that production optimization? Or is that kind of remediation type work? Is the -- what's the kind of mix of...

So the answer there, Nick, will be yes and yes. So usually, what you have is you'll have a well that may be struggling with a pump that's 2 years old. And again, the fact that we are able to get run lives of 2-plus years out of these pumps is almost unheard of in the Permian Basin. But for instance, when that will happen, we -- obviously, you would have an expense cost to go replace that or change the artificial lift. We'll take the opportunity at that point to go in, do a little bit of cleanout on the well, maybe a little bit of what I call small pump job, nothing like a frac job, a little asset and things like that to be able to optimize that production.

And then we typically lower where we pump the well from. So we will move down in the hole so that we can pull down the pressure we're pumping these wells at to a lower point, i.e., giving more drive from the reservoir into our well, and we're seeing great results from that. Some of these wells we're actually pumping deep into the curve, lowering our point that we're drawing that fluid from by as much as 250 to 300 feet. And with the reservoir we have with a little bit higher permeability, we're seeing great results from that. So you don't see it day 1. It takes time, but you're going to start seeing better and better recoveries from these wells.

[Operator Instructions] Our next question comes from the line of Jeff Robertson with Water Tower Research.

Just a follow-up, you said you're going to keep the second rig at least through the end of December. Can you just talk about how the carryover inventory will impact production at least in the first half or maybe first 3 quarters of 2026?

Yes, sir, absolutely. So we picked up the second rig October 15. Just kind of a rule of thumb for where we're at in the basin, we typically drill 2 wells a month per rig. So that will get us an additional 5 to 6 wells that we've drilled a little more than 2 per month now. So call it, 5 to 6 wells that we will have drilled in the fourth quarter in addition to the 1 rig program that will carry into 2026. Again, we're not talking about 2026 activity per se. Obviously, we laid out in the prepared remarks, a kind of high-level overview bear, base and bull case that will flow through our decisions on how we guide for 2026. Again, it's a little early. We'd like to see where oil prices kind of level out over the next month or so.

But to your point, bringing over those 5 wells because, again, anything you drill in the fourth quarter typically doesn't come online until the first quarter or early second quarter. So as we look into 2026, we will have somewhere in the range of 16 to 18 DUCs are wells in some form of completion that roll into 2026, again, supporting that kind of Q1 and Q2 production forecast.

Our next question comes from the line of Noah Hungness with Bank of America.

For my first question here, you guys yesterday filed an S-3. Could you maybe just talk about what the reasoning behind that was and if you had any plans with that moving forward?

Yes. Noah, this is Ryan. Great question. The sole reason for filing the S-3, our previous shelf registration statement that we had on file went stale and expired. So all we were doing was refreshing it. We have absolutely no intention of issuing any new shares anytime soon.

Great. And then given that we're kind of on the border here of your base and bear case. How long do you need to see prices kind of either sub-60 to drop activity or between that $60 to $70 to move into that base case? Is it a month? Is it a few weeks? Just how are you thinking about that?

So a couple of ways we're thinking about it, Noah. And obviously, there's -- it's a multivariate problem. Obviously, you can have a couple of days. You can even have a month. When you look at this year, we've probably averaged, I don't know, $63, $64 for the whole year. That would put you pretty squarely in between the bear and base case. Again, these aren't hard lines. There's going to be some squish between them. But if I look into 2026, even if you were in the bear case, something less than 2 rigs, again, remember, you pick up, it's kind of like -- they call it a dip switch, on or off, right? So you pick a rig up, it's on, lay it down, it's off. So in order to get something that's less than 2 kind of infers something more than 1, so call it 1.5. The way you would do that is drill with 2 rigs for a portion of the year and then lay it down.

Now kind of when I answered the question for Jeff on timing, when you drill these wells and when you bring them on are important for production throughout the quarters of the year. So in reality, I would foresee if we drill -- and with Board approval, obviously, if we chose to do more than 1 rig and we're in kind of the 1.5 to 1.7 rigs for next year based on whatever the oil prices look like toward the end of the year, we would most likely have that second rig going for the first portion of the year. So you may see us keep the second rig for some months into 2026. And then it would be determined by kind of oil price and long-term outlook as well as just the whole macro environment that we're in. It's very volatile right now. So I want to make sure that we keep that kind of long-term prudent look of what's going on in the market.

Got you. And just one more question. Could you maybe add some details around the distribution plan for '26 just regarding HighPeak Energy Partners II. Is this going to be just a single drop down to the LPs in one go? And then just a rough idea on timing within the year, if you could give that.

Yes. Noah, this is Ryan again. Really good question. At this point, I don't think we're prepared to lay out the exact plan, but the plan, like Mike said during his prepared remarks, is to be very methodical, which most likely translates to us slowly metering them out to the different LPs throughout the calendar year. Again, most of the limited partners have a very long-term investment mindset here. So it's nothing that causes us any concern from any kind of share overhang. We don't expect anybody to rush to sell by any means, especially at current share prices. But we will be very strategic and methodical about it. And it will most likely start early in the year, but will last throughout the calendar year.

And I'm currently showing no further questions at this time. This does conclude today's call. Thank you all for your participation, and you may now disconnect.

Thank you for standing by, and welcome to HighPeak Energy's Second Quarter 2025 Earnings Conference Call. [Operator Instructions]

I would now like to hand the call over to Steven Tholen, CFO. Please go ahead.

Good morning, everyone, and welcome to HighPeak Energy's Second Quarter 2025 Earnings Call.

Representing HighPeak today are Chairman and CEO, Jack Hightower; President, Michael Hollis; Vice President of Business Development, Ryan Hightower; and I am Steven Tholen, the Chief Financial Officer. During today's call, we may refer to our August investor presentation and our second 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 August investor presentation.

I will now turn the call over to our Chairman and CEO, Jack Hightower.

Thank you, Steve. Good morning, ladies and gentlemen, and thank you for joining us today for HighPeak Energy's second quarter conference call.

I'd like to thank the entire HighPeak team for all their hard work and continued dedication to the company while I was out during the quarter recovering from my accident. I'm extremely fortunate to report that I'm feeling much better, and I'm now back in the proverbial saddle.

Now turning our attention to HighPeak's second quarter results. We achieved another really strong quarter of production, albeit a little slower than first quarter levels, which was expected due to timing of turned-in-lines and with our deliberate reduction in development activity. In the face of lower commodity prices driven by geopolitical issues, the effect of newly instituted tariffs and global macroeconomic uncertainties, our margins remained quite strong at $33.58 per barrel of oil equivalent, allowing us to generate over $155 million of EBITDAX during the quarter.

We reduced activity in mid-May as prudent allocators of capital. And in conjunction with that decision, our second quarter CapEx spend was actually 30% lower than our first quarter spend. I'd like to remind everyone that due to the timing of bringing on large multi-well pads and our deliberate reduction of activity dropping down to 1 rig for a specified period of time and modifying our completion schedule with prescribed pauses of frac activity, our overall volumes will fluctuate from quarter to quarter. However, with our current development plan in place, we still feel confident that we'll achieve our '25 production guidance.

We're really excited about the recent refinancing of our term loan and super priority RBL and all the associated benefits, and we've added in some additional hedges since the quarter end, which will help us insulate from further potential downside in commodity prices as we move forward.

Now I'd like to turn the call over to Ryan Hightower to discuss the details of the term loan. Ryan?

Thanks, Jack, and good morning, everyone.

As Jack mentioned, we recently announced the amendment and extension of our current term loan and super priority revolving credit facility, which has solidified HighPeak's credit profile for the next several years. Outside of some associated upfront fees and expenses, it was a net debt-neutral refinancing transaction. Some of the material amendments and associated benefits to these facilities include the extension of all debt maturities by 2 additional years, pushing out expirations to September 2028.

The term loan facility was upsized to $1.2 billion, providing the company with essential additional liquidity. And given the current dynamic macro environment, we elected to push out the quarterly amortization payments until September 2026, which provides the company with more flexibility if we find ourselves in a lower-for-longer commodity price environment.

I would like to point out that one of HighPeak's top priorities is still to pay down absolute debt utilizing our free cash flow. So even though the amortization payments are on pause, look for the company to continue to pay down debt as we move forward. A few additional key benefits associated with this transaction include the term loan call protection or make-whole provision was not extended and will expire next month, which provides HighPeak with significant flexibility to pay down this loan at par in whole or in part at any time.

In comparison to a new high-yield bond with a standard 2- to 3-year no-call provision, this advantage creates substantial potential savings to the company in strategic alternative scenarios or if interest rates drop meaningfully over the next few years, and we want to lock in a lower rate with a high-yield bond at that time. The total upfront costs associated with this extension were significantly less than other potential financing options.

And if you agree with consensus estimates, another key advantage is the floating interest rate structure of the term loan, which will allow the company to benefit from projected lower interest rates. We are deeply thankful for the support of our lenders. This amendment and extension positions us to capitalize on future opportunities while maintaining a strong and adaptable financial foundation.

I'll now turn the call over to Steven Tholen to provide a brief update on our hedge profile.

Thank you, Ryan.

On a high level, HighPeak's hedging philosophy is focused on protecting our cash flows to fund our capital budget and service our debt. Subsequent to quarter end, when oil prices increased, HighPeak entered into additional crude oil derivative contracts covering a significant portion of our forecasted production volumes through March of 2027. The new hedges consist of mostly collars, but also include a few swaps. The collars generally have a floor price of $60 a barrel, providing HighPeak with downside protection should oil prices decline, but also offering exposure to the upside should oil prices increase.

Inclusive of our new hedges, we have over 50% of our volumes hedged for the second half of this year with a weighted average floor price of over $62 per barrel. Going forward, we will systematically hedge a minimum of 50% of our projected PDP crude oil production on a quarterly basis. We also have roughly 90% of our second half 2025 gas volumes hedged at a price of $4.43 per MMBtu. As Jack said earlier, these hedges will help insulate HighPeak from further downside risk in near-term commodity prices.

I will now turn the call over to our President, Michael Hollis, to provide an operational update.

Thanks, Steve.

As we previously guided to the market that our 2025 development program was first half weighted, as shown by our first and second quarter CapEx spend rates, as you can see depicted on Slide 8 of our company presentation. In conjunction with the updated development plan, we laid out our first quarter earnings call, we reduced activity down to 1 rig in mid-May, primarily as a result of the material D&C efficiency gains that we experienced over the last few quarters as well as in reaction to market and commodity price volatility post Liberation Day. HighPeak's second quarter CapEx was 30% lower than the first quarter, which was in line with our internal expectations.

Again, on Slide 8, you can see the monthly step down of capital spend, which decreased significantly after we dropped the second rig. June reflects the first full month running a single rig and is representative of what the 1-rig cadence spend rate would be. Looking forward, our plan remains to add the second rig in September. However, we are continuing to monitor commodity prices, the backwardation in the near-term as well as long-term strip, the overall market and our current cost structure, and we will remain flexible to adapt to those variables. Let me stress that we are not contractually obligated on any rig or frac crew. And as I mentioned on last quarter's call, 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 spend depending on market conditions.

Now to completion efficiencies. We are continuing to see D&C cost coming down. We are currently realizing low-single digit declines from where we were last quarter. I mentioned on last quarter's call, we revised our development schedule was going to afford us the luxury of introducing simul-frac operations on some of our completion jobs. During the second quarter, we completed our first simul-frac job on our Lorin Pad in Borden County. This was a 4-well 15,000-foot lateral pad. And I'm proud to report that this project went smoothly and even came in under our initial cost estimates, inclusive of the estimated simul-frac savings. We deployed 80,000 horsepower, completed roughly 4,500 lateral feet per day and utilized 80% recycled fluids for the stimulation. This was a strong first mark on the board for the completions group.

Now internally, we anticipated the savings in the neighborhood of $250,000 to $300,000 per well or roughly $1 million on this job. But after all was said and done, we actually saved closer to $400,000 per well, so about $1.6 million of total savings on this completion. This represents about a 10% savings on our total completion costs. HighPeak expects to utilize simul-frac operations on roughly 1/3 of our remaining completions during the balance of 2025 based on our current development schedule, further enhancing our capital efficiency. Given the tremendous success of our first simul-frac, we will look to insert simul-frac ops anywhere that we can fit it into our completion schedule.

And now for a quick update on our Middle Spraberry delineation process. Our first Middle Spraberry test in Flat Top, which was a 10,000-foot lateral has cumed over 170,000 barrels of oil plus associated gas in less than 1 year of being turned online, which has significantly outperformed our initial type curve estimates and is consistent with the results of our bread and butter Wolfcamp A and Lower Spraberry wells. This level of first year well performance, coupled with our current cost structure would equate to single well breakevens in the low- to mid-$40 per barrel of oil range.

Our second well, which is a 15,000-foot lateral, is continuing to ramp up and looks very encouraging. It has cumed over 50,000 barrels of oil to date. Offset operators have continued to drill and delineate the Middle Spraberry formation around HighPeak's acreage. These are all constructive steps towards delineating approximately 200 Flat Top Middle Spraberry locations that will eventually move into HighPeak's sub-$50 breakeven inventory.

And now turning to Signal Peak. We recently turned in line our easternmost Wolfcamp A and Lower Spraberry wells, which include 1 Wolfcamp A and 2 Lower Spraberries. All 3 wells are currently cleaning up and producing a combined 1,500 barrels of oil per day plus associated gas. It's still early in the flowback process, but we are very encouraged by the early results and the development potential this area may provide. Please note that HighPeak does not carry any inventory in these zones east of where these wells have been drilled, but the early encouraging results may allow us to add incremental inventory further east in our block.

Our Flat Top solar farm has now been online for a little over a year, reducing our electrical cost as well as our Scope 2 corporate CO2 emissions. From June through December of last year, we realized power savings of about $810,000 while reducing our CO2 emissions by over 4,600 metric tons. The amount of power generated from the solar farm, while it was online for 7 months in 2024, was the equivalent of the annual energy usage of roughly 1,100 homes. From a social standpoint, we're proud to say that HighPeak is reducing our grid power usage by 10 megawatts during peak summer power demand hours to be utilized by the communities that we operate in.

And with my comments now complete, I'll turn the call back to Jack for closing remarks.

Thank you, Mike.

In closing, it was a solid quarter for HighPeak. The operations team are doing a stellar job and are laser-focused on optimization and corporate efficiency. The entire organization holds our 4 core pillars paramount. Number one, improving corporate efficiency. The HighPeak machine continues to squeeze out efficiencies throughout the entire development and production process. We're currently realizing low-single digit declines in well costs quarter-over-quarter and the successful use of simul-frac is a true needle mover. And remember, HighPeak expects to simul-frac approximately 1/3 of its completions for the remainder of this year.

Number two, maintaining capital discipline. Because of our realized operational efficiency gains in the current state of global economic uncertainty and its impact on oil prices, we had taken the proactive step back in May to modify our drilling cadence by dropping a rig. We're still currently running one drilling rig with the plan to pick up the second sometime next year -- next month, which would allow us to perform all the development work we guided to at the beginning of the year. However, we will continue to monitor market conditions, and we will remain flexible to further adjust our program as those conditions warrant. We have no obligation to add back the rig and may choose to delay its arrival.

Number three, optimizing our capital structure. As you may recall, one of the main '25 objectives was to optimize our capital structure. In light of the overall market volatility post Liberation Day, the recent amend and extend of our term loan and revolving credit facility was the best outcome for the company. This action prevented the prior outstanding term loan balance from going current on our balance sheet in September. This refinancing has solidified our credit profile by extending our debt maturities until 2028. It's increased our liquidity, minimized our upfront refinancing costs and provided us with the benefit of realizing potential interest expense savings. If interest rates come down over the next few years as projected by consensus estimates, in addition with the prepayment penalty set to expire next month, we will have the ultimate flexibility of continuing to pay down debt at par as we generate free cash flow moving forward.

Four, creating shareholder value. This is the time to stay nimble and prudent, which our high-quality asset base allows us to do. Management continues to be hyper focused on long-term value creation. And it's important to remember that while markets may be temporarily volatile, the fundamental value of our asset base remains strong. We're 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 return.

Thank you very much, and now we'll open up the call to questions.

[Operator Instructions] Our first question comes from the line of Jeff Robertson of Water Tower Research.

On the financing side, Steve or Ryan, can you talk a little bit about how much liquidity you want to maintain? And I'm just thinking about it in the context of the ability to pay off principal amounts on the term loan as you look at the rest of 2025. I know the required amortization expires, but you have the flexibility to pay off term loan balance with excess cash flow to the extent you maintain whatever liquidity level you're looking at?

So Jeff, I think we'd like to maintain a fair amount of liquidity. It's going to be based on where oil prices are. We're also where we're able to put in hedges that protect us on the downside if oil prices should turn down. But it be our intent that over the course of time that as we generate free cash flow that we will use that free cash flow to pay down debt. But we have currently over $200 million to over $250 million of liquidity at this point in time. It's a number that we feel pretty comfortable with. And -- but it will be dependent on where oil prices go as we go forward.

Steve, on the cash flow statement, can you talk at all about the swings in the working capital changes that are in the investing cash flows and how that might trend over the rest of 2025 with the capital program you have in place?

Yes. So what you're seeing there is the effect of reducing from 1 -- from 2 rigs down to 1 rig. And as a consequence, there was a large adjustment in the accounts payable and working capital during the second quarter. As we are at 1 rig and we -- through the end of -- or through the majority of the third quarter, we'd expect that number to be relatively static as we go forward as we pick up a second rig in September or later this year, we would expect that number to increase and be a benefit to the cash flow from operations.

And Jeff, also remember that we had some infrastructure projects that kind of ran through the latter half of Q1 and some of the bills flow into Q2. So some of that is part of this net working capital that you saw in Q2 as we dropped activity.

Yes. Yes.

Mike, with respect to operations, you said you're going to -- about 1/3 of the remaining completions will be via simul-frac. Is there a limit on -- or is there -- are there any limiting factors on why you couldn't complete more wells with simul-frac? Or does it just depend on where they're drilled and what pads and how the development cadence works out?

You bet, Jeff. Obviously, when you're playing with kind of the rule of small numbers, which would be 1 to 2 rigs and today, 1, it's a little bit more difficult to drill large kind of 4, 6-well pads. We have some of those that we have to complete in the rest of this year. Now as you -- so again, in simul-fracking, you are fracking 2 wells at one time and usually doing wireline perforation work on the other 2. So ideal is 4 or more wells on a pad to be able to simul-frac effectively and efficiently.

However, we are going to start looking at how we could do what we are kind of coining hybrid simul-fracs on wells or pads that may only have 3 pad or 3 wells on a pad. It won't be the same kind of $250,000 to $400,000 of savings. It might be more like $50,000 to $100,000. But we are looking at that to see how we can utilize this more effectively on a higher percentage of our completions, both this year as well as going into the future. Obviously, with a higher number of wells that you drill or number of rig count, it's much easier to have at least 4 or more wells on a pad. So hopefully, that kind of gives you a little color.

And then in the deck, you say it shows that you have 20 wells in progress at the end of the second quarter. How does the inventory of wells in progress and looking out into 2026 affect your decision-making as to whether or not to add a second rig this fall?

So the 20 DUCs that we came into the quarter with kind of an average rule of thumb per operating rig would be roughly 10 per operating rig behind it because you're always either drilling on a pad with some wells that have DUCs or you're completing, drilling out, putting equipment in. So coming into second quarter and having 20 makes perfect sense. Now the longer that we run just 1 rig and complete at our normal cadence, you'll start to see the DUC count behind us start to come down and approach that 10 wells if we were to do it per rig if you're only running 1 rig, and you did that for an extended period of time. So do I think it's going to come down to 18, 17 by the end of the year, that's probably a pretty good number. Now to that point, whether or not we were to pick a rig up or not this year, we have almost every well drilled currently that will be completed this year.

On the operational highlights, you talked about the Middle Spraberry, Mike. Will you see -- do you anticipate that you will see much of an impact from that inventory on your year-end 2025 reserve numbers?

So the answer will be obviously a lot more impact than we had in 2024, right, because we had just drilled 1 well and so really very few to no PUDs associated with it. I think it would be reasonable to expect that we would probably drill 1 to 2 more Middle Spraberries this year, plus the additional drilling that's been done off to our flanks by our offset operators could add some additional PUDs associated with those. So yes, the total number of PUDs associated with Middle Spraberry wells at the end of 2025 will be significantly higher than it was in '24.

And lastly, if I can, can you talk based on the completion schedule that you look at, can you talk a little bit about where you think production might go over the next couple of quarters?

You bet. No. And obviously, Jack kind of mentioned it, when you're doing these pads, you do get a little bit of lumpiness. I think when you look at our yearly production guide and the fact that Q1, we had a pretty good month where everything kind of timing-wise ebb and flowed in our direction. And then you look at second quarter, it's just a matter of timing of when we brought these wells on.

And obviously, when you frac wells, you water pads out on either side. So you'll see some fluctuations quarter-to-quarter. In Q1, obviously, we model out all of these things. So you saw a very modest change in our midpoint of our guide for our production. And I think looking forward, that will be a pretty good guide for everyone from where we are to the endpoint. Again, we don't give quarterly guidance for that reason, but I think our yearly guidance is still solid, yes.

Thank you. And that does conclude the Q&A portion of our call and today's conference call. Thank you for participating. You may now disconnect.