HighPeak Energy (HPK) Q2 2026 Earnings Call Transcript

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DATE

Tuesday, Aug. 11, 2026 at 11:00 a.m. ET

CALL PARTICIPANTS

• Chief Financial Officer - Steven W. Tholen
• President and Chief Executive Officer - Michael L. Hollis
• Executive Vice President - Daniel Meads
• Senior Vice President - Christopher Mundy

TAKEAWAYS

• Revenue -- $272.4 million in the second quarter, primarily consisting of $260.4 million from crude oil sales.
• Net Income -- $82.3 million for the second quarter, or $0.59 per diluted share.
• EBITDAX -- $147.6 million, representing $1.06 per diluted share for the quarter.
• Sales Volumes -- 45.3 MBoe/d in the second quarter, with liquids making up 83% of the total volume.
• Unhedged Realized Oil Price -- $98.82 per Bbl, representing 71% of the weighted average NYMEX crude oil price.
• Unhedged Realized Gas Price -- negative $1.50 per Mcf, reflecting high negative Waha differentials during the quarter.
• First Half Production -- 45.5 thousand BOE per day, exceeding the high end of the guided range.
• Hedged Realized Gas Price -- negative $0.61 per Mcf, including the impact of $55 million in net cash hedge losses.
• Unit Lease Operating Expense -- $7.56 per BOE for the first half of 2026, coming in 13% below the midpoint of full year guidance.
• Total Cash Costs -- $17.02 per Boe in the second quarter, which includes $6.43 for lease operating costs and $4.18 for gathering and transportation.
• Capital Expenditures -- $107.5 million for the second quarter, bringing the first half total to $185.9 million.
• First Half Budget Allocation -- 69% of the annual development work was completed in the first six months due to the decision to pull forward completion activities.
• Drilling Progress -- 17 operated wells drilled in the first half of 2026 against a planned 29 wells for the full year.
• Completion Progress -- 24 horizontal wells completed in the first six months, compared to the annual target of 33 wells.
• Turn-in-Lines -- 20 wells turned to sales in the first half of 2026, positioning the company toward a 37-well full year target.
• Crude Oil Percentage -- 64% of total sales volume in the second quarter, impacted by temporary water out from completion activities.
• Inventory in Progress -- 21 gross horizontal wells remained in progress as of June 30, 2026, with 16 wells in various stages of completion.
• Cash Balance -- $146.3 million as of June 30, 2026.
• Debt Amortization -- $30 million per quarter scheduled to begin at the end of the third quarter of 2026 for the term loan.
• Oil Hedge Portfolio -- Majority of oil hedges are established in the mid-$60 per barrel range to provide downside protection.

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RISKS

• Hollis stated, "So to your point, we have watered out our frac-impacted even more oil than we had initially anticipated," regarding the impact of intensive second quarter completion activity on existing production volumes.
• Hollis noted that negative Waha differentials averaged negative $1.50 per Mcf during the second quarter, although management expects realizations to improve as new pipeline expansions come online.

SUMMARY

Management reported a transition into a maintenance mode development plan, prioritizing the generation of free cash flow through front-loaded capital investment. The company stated that production volumes for the first half of 2026 exceeded original guidance ranges, supported by high drilling efficiencies and an active workover program. Management noted that capital spending is expected to decline significantly in the second half of the year because approximately 69% of the annual development work has already been completed. The company indicated that its financial strategy focuses on amortizing its term loan debt at a rate of $30 million per quarter while utilizing a mix of swaps and collars to mitigate commodity price volatility.

• CEO Hollis attributed the decision to accelerate completion work to favorable market conditions, stating the company "saw an opportunity to lock in attractive frac pricing and continue working with a simul-frac crew."
• Hollis stated that a large portion of expected oil production remains "exposed to market pricing," allowing the company to participate in potential commodity price strength.
• Management expects the oil cut to return toward a range of 67% to 68% for the remainder of the year as the impact of watered out volumes from the high-intensity completion quarter subsides.
• Hollis described the workover program as a way to "maximize the value of every asset that we already own" by investing a fraction of new-well costs to bring production back online.
• Management indicated that approximately 10 to 12 drilled but uncompleted wells (DUCs) will move into 2027, maintaining a cadence similar to the current development program.
• The company added NYMEX WTI roll swaps and Waha Basis swaps during the quarter to manage calendar spread exposure and reduce exposure to West Texas natural gas price fluctuations.
• Hollis indicated that Permian gas takeaway capacity should be sufficient for the next 12 months following recent pipeline expansions, despite historical volatility in the Waha market.

INDUSTRY GLOSSARY

• Boe: Barrel of Oil Equivalent, a unit of energy based on the approximate energy released by burning one barrel of crude oil.
• DUC: Drilled but uncompleted well, which has been drilled to depth but has not yet undergone hydraulic fracturing.
• EBITDAX: Earnings before interest, taxes, depreciation, amortization, and exploration expenses, a common metric in the oil and gas industry to measure performance.
• LOE: Lease Operating Expense, the costs incurred by an operator to keep wells producing after they have been drilled and completed.
• MBoe/d: Thousand Barrels of Oil Equivalent per day.
• Simul-frac: A technique where two separate wells are stimulated simultaneously using a single spread of equipment to increase operational efficiency.
• Waha Basis: The price difference between natural gas at the Waha hub in West Texas and the national benchmark at Henry Hub.

Full Conference Call Transcript

Operator: Good day, and welcome to High Peak Energy. 26 Second Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. To ask a question during the session, you need to press *11 on your telephone. You will then hear an automated message advising your hand is raised. To answer your question, please press *1 again. Also, the call is being recorded. I would now like to turn the call over to Steven W. Tholen, CFO. Please go ahead.

Steven W. Tholen: Good morning, everyone, and welcome to HighPeak Energy's Second Quarter 2026 Earnings Call. Representing HighPeak today are President and CEO, Michael L. Hollis; Executive Vice President, Daniel Meads Silver Senior Vice President, Christopher Mundy; and I am Steven W. Tholen, the chief financial officer. During today's call, we may refer to our August presentation and press release which can be found on High Peak's website. Today's call participants may make certain forward-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-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 Invest August investor presentation. I will now turn the call over to our President and CEO, Mike Hollis.

Michael L. Hollis: Thank you, Steven. Good morning, everyone, and thank you for joining us today to discuss our second quarter 2026 results. It was another strong quarter for HighPeak. Our team continued to do what they have consistently done. Execute the development plan operate efficiently, spend capital responsibly, and focus on creating long-term value for our shareholders. Production during the quarter was essentially flat with the first quarter and once again came in above the high end of our guidance range. That performance reflects the quality of our assets and more importantly, the ability of our operations team to consistently deliver results.

From a capital spending perspective, the second quarter was expected to be our highest spending quarter of the year when we built our 2026 plan. During the quarter, we also chose to pull forward some completion activity that was originally scheduled later in the year. We saw an opportunity to lock in attractive frac pricing and continue working with a simul-frac crew that has been generating meaningful efficiency gains faster cycle times, and lower cost. When we see opportunities to improve returns and create additional value, we are going to take advantage. of Advancing that work allowed us to do exactly that. While staying within the disciplined framework we have used throughout the year.

As a result, we expect capital spending to decline meaningfully during the second half of 2026. Which is consistent with our original plan and reflects the amount of development work completed during the first 6 months of the year. On the cost side, our team continued to make solid progress drill, complete, and equip costs remained in line with expectations, and we continue to drive operational improvements across the field. Lease operating expense performance was particularly strong with the first half unit LOE coming in approximately 13% below the midpoint of our full year guidance. it is worth noting that these results include the impact of an expanded workover program that we intentionally pursued during the quarter.

As commodity prices improved, we identified opportunities to invest modest amounts of capital into low-cost, high-return workovers that brought meaningful production back online as well as enhanced the productivity capability of those wells. All while generating attractive economics. We will discuss that program in more detail later because it highlights the kind of practical return-focused decision making that drives value at HighPeak. Financially, stronger realized oil prices combined with consistent production drove sequential growth in both adjusted EBITDA and free cash flow. We achieved those results despite absorbing approximately $55 million of net cash hedge losses during the quarter. Looking ahead, a larger percentage of our expected production remains exposed to spot pricing.

Which positions us to benefit if commodity prices remain supported by the ongoing uncertainty in the global supply market. Bottom line, we are pleased with where the company stands today. Our priorities have not changed We are going to continue developing our assets safely and efficiently allocating capital with discipline, keeping a close eye on costs, and building a stronger business quarter over quarter. that is how we have operated for multiple years now and that is how we will continue creating value for our shareholders. Turning to Slide 5 and 6 of our investor presentation. These slides highlight the progress we have made against our 2026 development plan throughout the first half of the year.

The operations team continues to execute at a high level across the board. On the drilling side, we kept driving efficiencies and drilled 17 of our planned 29 wells during the first 6 months of the year. On the completion side, we completed 24 of our planned 33 wells for the year reflecting the decision to pull forward a portion of our second completion activity and take advantage of favorable market conditions. As we have discussed, the accelerated completion schedule allowed us to capitalize on attractive service costs and continue working with a high performing simul-frac crew. That has consistently delivered strong results.

Despite some additional fully expected frac impact oil volumes, production was supported in the quarter by the success of our workover program. Program, and the associated oil volumes from that work. We have already turned 20 wells into sales this year, which puts us in a strong position to achieve our full year target of 37 turn-in-lines. When we built our 2026 development plan, we expected roughly 60 percent of the year's capital to be spent in the first half. Because we elected to accelerate a portion of our completion activity, first half spending ultimately moved into the mid- to upper-60% range of our annual budget. Now that was not unplanned spending.

It was capital deployed against productive work that generated value and advanced our development program ahead of schedule. The benefit of that strategy is that a significant amount of this year's development work is now behind us We have put ourselves in a position to maintain strong production levels while materially reducing capital spending in the second half of the year. that is exactly the kind of setup we like. We get the benefit of the work completed earlier in the year. Lower capital requirements going forward, and the opportunity to generate stronger free cash flow through the balance of 2026.

Most importantly, we are accomplishing that while staying disciplined executing the plan, and continuing to focus on long-term value creation for our shareholders. Turning to the base production optimization. 1 of the best examples of value creation during the quarter was a successful workover program As commodity prices improved, we saw an opportunity to put additional capital to work in parts of the business where the returns were compelling and the risk was low. Our team went well by well across the asset base, and identified opportunities for a relatively small investment could bring meaningful production back online as well as enhance the productive capability of those wells. Again, all while generating attractive economics.

We like these projects because they are straightforward. Capital efficient, paid back quickly. In many cases, we are investing a fraction of what it costs to drill a new well while getting production back online in a much shorter time frame. From a returns perspective, these are some of the highest value opportunities we have available. The workover program is not a replacement for our development program, it is a complement to it. We are continuing to develop our inventory, and we are also making sure we maximize the value of every asset that we already own. that is just good field management. At HighPeak, we have always believed capital should go where it can generate the strongest returns.

Whether that is drilling a new well completing a DUC, or putting capital into a workover, we are going to evaluate every opportunity the same way. The goal is simple. Invest wisely, increase production, generate more free cash flow, and create long-term value. This quarter's workover results are another example of our team's operational focus and disciplined approach to capital allocation. We identified an opportunity moved quickly to capture it, and delivered strong return on that investment. Now looking ahead to the rest of 2026, we are in a good position. A large portion of our expected oil production is exposed to market pricing. Which gives us a greater participation if commodity prices remain strong.

At the same time, we are not in the business of speculating. We are in the business of generating cash flow and protecting returns. that is why we continue to maintain a solid hedge position with the majority of our oil hedges sitting in the mid-$60 per barrel range. Those hedges provide meaningful downside protection while still allowing us to benefit from a stronger price environment. We take a practical and disciplined approach to risk management. During the quarter, we added a number of positions designed to reduce volatility and protect cash flow where we saw the opportunity to do so at attractive levels.

Specifically, we added NYMEX-WTI roll swaps to manage calendar spread exposure and Waha Basis swaps to help reduce our exposure to fluctuations in West Texas natural gas prices. The objective is pretty simple. We want to protect the balance sheet preserve cash flow, and maintain the financial flexibility to continue executing our development plan regardless of where commodity prices move in the near term. We believe that is the right approach for our shareholders We hold meaningful upside when markets are strong but we also want to make sure that we are protecting the business during periods of volatility This approach positions HighPeak to continue generating value for shareholders in any market environment. Turning to our first half.

2026 operational and financial scorecard, I think this slide tells a pretty simple story. Our team went out and executed. Across the board, we either met or exceeded the goals we set for ourselves while continuing to stay disciplined on cost, capital, and operations. Production averaged 45.5 thousand BOEs per day during the first 6 months of the year. Exceeding the high end of our guidance range that is a direct result of strong well performance disciplined execution of our development program, and the ongoing work our team is doing to maximize the value of our existing production base. On the cost side, the results were equally strong.

Unit LOE averaged 7 dollars and 56 cents per BOE, which came in approximately 13% below our guide level. that is not the result of a 1-time event. Or simply getting lucky. it is the result of years of work focused on building more efficient operation through infrastructure improvements, electrification, field-level optimization, and a culture that is constantly looking for ways to do things better. Most importantly, these cost savings are proving to be durable, and sustainable. Our development program also continued to perform exactly as planned. During the first half, again, we drilled 17 operated wells, completed 24, and turned 20 wells into sales.

As we discussed earlier, we made the decision to accelerate a portion of the completion activity into the second quarter to capture favorable service costs. That decision allowed us to get more work done sooner improve capital efficiency, and position the company for significantly lower capital spending during the second half of the year. From a capital standpoint, we invested $185.9 million during the first 6 months of 2026. Even with the accelerated completion program, we remained fully aligned with our full year development budget. We did not spend more money We simply chose to spend a portion of it earlier to capture efficiencies and create additional value.

The combination of strong production lower operating costs, and disciplined capital execution generated approximately $281 million of EBITDAX during the first half. Those results highlight the quality of our asset base the strength of our operating model and the cash-generating capability of the business. At the end of the day, this is exactly the kind of performance we strive for. We delivered production above expectations, kept costs under control, executed the development plan, and maintained capital discipline. More importantly, we position the company to generate stronger free cash flow during the second half of the year as capital spending comes down while production remains strong. that is the formula we are focused on.

Consistent execution, efficient operations, disciplined capital allocation, and creating long-term value. As we wrap up today's prepared remarks, I leave you with a few final thoughts. HighPeak is exactly where we want to be. We built this year's plan with the understanding that commodity prices would remain volatile. And we manage the business accordingly. The results we are delivering today reflect the strategy that was designed to generate strong returns and free cash flow across a range of market conditions. Not just in the perfect environment. Our maintenance mode development program is doing exactly what it was intended to do. We are maintaining strong production, spending substantially less capital than we have in prior years.

And generating increasing amounts of free cash flow. Just as important, we preserve flexibility. If market conditions change, we have the ability to adapt while continuing to focus on long-term value creation. We cannot control commodity prices interest rates, or geopolitical events. But we can control how we operate the business, and that is where our focus remains. We will continue allocating capital with discipline, protecting the balance sheet, driving operational efficiencies, and generating substantial free cash flow. We have always believed that successful companies are built by making sound decisions quarter after quarter and year after year. And that is exactly what we are doing at HighPeak today.

We have a high quality asset base, a proven team, and a development inventory that gives us confidence in the future of this company. Most importantly, we are committed to creating long-term value for the people who have invested alongside us. Our strategy is straightforward, operate efficiently, spend capital wisely, and generate strong returns and let the results speak for themselves. Before we close, I want to thank the employees. The results we discussed today are a direct reflection of their hard work, commitment, and focus on operating safely and efficiently every day. I would also like to thank our shareholders for their continued support and confidence in HighPeak.

We do not take that trust lightly and we are committed to earning it every day. With that, operator, we are ready to open the call for questions.

Operator: Thank you. You will hear an automated message advising your hand is raised. If you would like to remove yourself from the queue, press *1 again. We also ask that you wait for your name and company to be announced before proceeding with your question. 1 moment while we compile the Q&A roster. Our first question is coming from the line of Jeff Robertson of Water Tower Research. Please go ahead.

Jeff Robertson: Thank you. Good morning. Mike, can you talk a little bit about the impact on second quarter production from accelerating some of the completions into the quarter. And what you would anticipate for the rest of the year just based on your schedule of additional wells to turn in line?

Michael L. Hollis: Absolutely, Jeff. Noah, Great question. You know, obviously, with a smaller production base and as we move activity around, more specifically on the completion side of the business, you do affect existing production by stimulating wells at a certain area. We have got a refer to that as water out or frac-impacted oil volumes. So as you can imagine, second quarter was going to be a more active completion-intense quarter by design, and then we pulled 4 additional completions into that quarter. So to your point, we have watered out our frac-impacted even more oil than we had initially anticipated.

So when you look at our kind of maintenance mode program, you will have some lumpiness as we move that frac crew around and have breaks in the schedule, you will see if you were looking at daily volumes, you will see some movement. But, again, we guide on a yearly guide, And when you look at the first 6 months of the year, we are above that guided range pretty significantly. And there is a lot of pieces that go into that. The actual well performance that we are seeing from our development program, And we talked a little earlier about the workover program, but the read through there is that the budget is set.

We just pulled forward some of that opportunity because we had a condition where we had a good frac crew at a good price in a good market. And they were very efficient and effective. So we went ahead and let them do a little more work. But for the whole year, what the read through is, obviously, less capital will be spent in the second half of the year. The drilling rig schedule was a little tough, right? Because it is 1 rig. it is either a on or an off. So the plan is to continue to drill with that 1 rig throughout the entire year.

And, again, you can kinda see in the first 6 months, we drilled 1 additional well above what we had planned for the year. Just because of the drilling efficiencies throughout the year. So we would expect something similar for the second half of the year, maybe 1 additional well drilled. But the drilling portion of capital spend is fairly small. Think somewhere in the 30% range of a well's AFE. Now on the completion side, the read through there is we will do the budgeted amount of completions throughout the year. We just performed 60-9 percent of that work in the first half of the year.

So think less water out volumes as you go throughout the rest of the year not like what we have had in the first half. As well as some impact from the workover program that we have. We think volumes will stay strong. Throughout the-- I cannot speak-- last half of the year. And, hopefully, commodity prices are supportive as well. But at any reasonable oil price, we will generate significant free cash flow throughout the remainder of 2026.

Jeff Robertson: Mike, I know it is way too early to talk about or it is too early to talk about 2027 guidance, but can you just talk about the cadence in the second half of 2026 and maybe in the drilling spilling over into the first part of 27. And will the setup for next year from a production standpoint be somewhat similar to what you all were thinking when you came into 2026?

Michael L. Hollis: Absolutely, Jeff. So the original plan was to have somewhere in the 10-plus DUCs move into 2027 out of this year's program. Being able to drill 2 additional wells throughout the year just because the rig is that much more efficient Just means 2 additional DUCs move in 2027. The fact that we are only going to do the set number of completions we had in the budget Again, 2027 is set up to look a lot like 2026 as far as capital requirements as well as production volumes.

Jeff Robertson: Just turning to the balance sheet, Mike, you had $146 million of cash at the end of the quarter. And scheduled amortization of the term loan $30 million per quarter starts at the end of the third quarter. Can you talk a little bit about how you are thinking of liquidity on the balance sheet and paying down or amortizing the term loan and the free cash flow build, and would it be reasonable to expect that you amortize the term loan the extent you can faster than the $30 million per quarter?

Michael L. Hollis: Jeff, great question. Obviously, we will amortize at $30 million a quarter. Now in order to do more than that, what we have to manage in the future is we need enough cash that, obviously, at today's oil prices we are going to generate much more than that $30 million a quarter to be able to meet the amortization and have a cash build. However, we need to be a little careful with prepaying too much because you cannot get that money back. it is not like a revolver where you can reborrow it. So you will see us be a little more cautious to paying down above the $30 million for the next quarter or so.

But, again, it all depends on what that free cash flow generation per quarter, which again, mainly driven by what the oil prices are for the quarter, which we cannot guess right now. But we will definitely do the $30 million a quarter, and we will have enough cash on hand to be able to weather any kind of variability over the next year or so, think 2027 and beyond. Thank you, Mike. Yes, sir. Thank you, Jeff.

Operator: Thank you. 1 moment for the next question. Our next question is coming from the line of Nicholas Pope of Roth Capital.

Nicholas Pope: Morning, guys. Hey. Quick questions here. Looking at the work over load that you all had in the quarter, saw a bit of an uptick. You highlighted it that there is a lot of work to do there. Curious how to think about inventory like, what the running room is on those workovers, and how those manifest themselves either in production or cost where that necessarily shows up in the income statement. Kind of where you all expect to see the benefit. And how much, like, sight you have on the potential for more of those workovers.

Michael L. Hollis: Sure. Nick, I would love to tell you that wells never fail and operations are really easy. Now our job is to always make them look very stable, easy, and nothing to see here. But in the operations world, you always have things happen. So, typically, when we choose to do a workover, we will not take a well that is producing just fine and go take that production offline to go do this work over. Eventually, something will happen on that well to where you have to do an intervention.

Now when you talk about the pace going forward, through the first half of this year, we have called up most of what we had kind of banked as wells that we could go quickly pull forward. So on a go forward basis from more or less from now until, you know, in memoriam, Wells will need to be worked on. I mean, we have to be there to do the work. that is when we will do the additional work over expense of the little mini stimulations. The acid surfactants, all of those things as well as lowering pumps, doing things to optimize the reservoir's capability of delivering into that wellbore.

But, again, we cannot really forecast with exact precision when a well is going to fail because we are always working on the other side of that equation to keep that well producing and keep our LOE cost down. So we are kind of on both sides of that equation, but I want you to hear the read through is there will always be opportunity for these workovers. From now until the future. The big answer for us and where it shows up, for cost, it shows up in the LOE side.

Because a lot of that work was something you were going to have to do because you had rods fail, and you had to go pull rods and replace things. that is all on the LOE side. On the capital side, we capture if we are doing any kind of mini stimulation that we think would increase reserves from that wellbore. Hopefully, that-- Got it.

Nicholas Pope: Answered. Thank you. Yes, sir. And then kind of further on some of the questions that Jeff had talking about looking at the quarter, the gas weighting, you know, obviously, had a lot more gas volumes, had the negative gas prices during the quarter. Curious what you all are seeing here in the second half of the year, both with pricing and being able to move that gas And how much of that kind of that weighting, you know, somewhat transient with some of the work that got brought forward with that high gas volumes. And your ability to manage that in the second half of the year?

Michael L. Hollis: Great. Great setup for me there, Nick. I really appreciate that because I am actually gonna step back a little bit to tell you why the oil percentage went down to 60-4 percent. From our guided range of 60-7 to 60-8 percent. Couple reasons. And you kinda saw this in fourth quarter of 25 where we did a lot of simulations in that quarter in high production areas, so think water out frac impacted. We did the same thing in the second quarter.

So a lot of your high oil content wells, say a well making a couple of 3, 400 barrels a day, is going to be at a slightly higher oil cut than wells that are producing you know, say, 100. And that is important here in a second when I tell you some of the other things we did. So we watered down a lot of high oil cut production. That brings down your oil percent for the quarter. But offsetting that as well, we also worked over several call it, kind of a 100 you know, 80 to 100-barrel-a-day older wells, that have a higher gas cut.

Not only did we get them back online, but we did the mini stimulations that increased their production. So that was some of the offset that we had in 2020 or I am sorry, in the second quarter and why our production remained flat. In spite of those additional watered out volumes. But that will come at a slightly higher gas ratio than new wells that come on very oil rich. So that is why it was 64%. So what is the read through for the rest of the year? Again, we feel comfortable with our 60-7 to 60-8 percent oil cut.

Now that we are halfway through the year and we are I would probably lean a little closer to the 67% of the range is what I would expect to happen through the rest of the year. Now you had a couple other questions about you the cost that we received. You know, the entire industry got some pretty horrendous cost of gas in the second quarter. Very high negative Waha differentials.

If you look at HighPeak compared to most of our peers, I think our dollar negative $1.50 that we turned in for the second quarter is very respectable compared to all of our other public peers, and we will be at kind of that top tier portion of being negative, I guess. that is a bad way to say it. But looking forward, so what do things look like now? With Gulf Coast Express expansion happening or online? Matterhorn Express, you have seen that Waha differential now closer to the minus $1 from what was minus $3 to $5. An MCF. So what does that mean going forward?

The negative number that goes into your realized price is a lot smaller for the rest of this year. So we will see much better realizations from our gas going forward. And we have taken some steps to help hedge some of that volatility Because 1 thing the Permian operators are extremely good at is filling pipes. And pipes are always late. So we will see tightness in the future in the late 2027 into 2028. So we need to prepare for that. But as we sit right now for the next 12 months, gas takeaway is not an issue. We have not had 1 MCF that we were not able to put into a pipe.

We just were not getting paid for it. We had to pay for them to take it. Going forward, that will be much better in 2026 and at least through the first half of 27. Got it. I appreciate the time. I will let you move on.

Operator: Thank you. Thank you, Nick. Thank you. And there are no more questions in the queue. That does conclude today's program. Thank you all for joining, and you may now disconnect.

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