Good day and thank you for standing by. Welcome to the HighPeak Energy 2022 Q2 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during this session, you will need to press star one one on your telephone. 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 Q2 2022 conference call. Representing HighPeak Energy today are Chairman and CEO Jack Hightower, President Michael Hollis, Vice President of Business Development Ryan Hightower, and I'm Steven Tholen, the Chief Financial Officer. During today's call, we will make reference to our August investor presentation and our Q2 2022 earnings release, which can be found on HighPeak Energy's website. Today's call participants may make certain forward-looking statements relating to the company's financial condition, results of operations, expectations, plans, goals, assumptions, and future performance. Please refer to the cautionary information regarding forward-looking statements and related risks in the company's SEC filings, including the fact that actual results may differ materially from our expectations due to a variety of reasons, many of which are beyond our control. We will also refer to certain non-GAAP financial measures on today's call, so please see the reconciliations in the earnings release, which was issued yesterday afternoon. Our prepared remarks will begin on slide four of our August investor presentation. I will now turn the call over to our Chairman and CEO, Jack Hightower. Steve, thank you very much for the introduction, and I am extremely excited about this quarter's performance and our growth, continued growth strategy, being able to execute that. I'd like everybody to think about the press release and earnings release that we just had. In looking at that and studying that, it's just been a phenomenal quarter. You could say it's business as usual in terms of executing everything we set out to accomplish in the quarter. We, of course, increased our legacy HighPeak production volumes substantially. If you think about going from 12,000 something on a pro forma basis to almost doubling that, we ended up integrating properties and infrastructure into our operations. We ended the quarter with 6 rigs running and 3 frac crews running, which was an increase when you think about last year's business of almost 3 times the number of. We had 1 rig running most of last year, and now we have 6 rigs running. We commissioned our Flattop electrical substation project, and we're in the process of converting our Flat-Top field operations to electrical power. Our Sandmine partnership became operational in June, and we're integrating that into our completion operations. We increased our revolving credit facility up to $400 million, and we added multiple banks to our group syndication. I wanna definitely congratulate our team in that with what we were able to accomplish, increasing our drilling activity, field operations, integrating the acquisitions without having to add significantly to our personnel and our employee base, and continuing to lower our lease operating expenses and on a per BOE basis, lower our G&A per barrel. We are evolving on a quarterly basis, as evidenced by our track record of consistent, responsible growth. I've talked about that many times. Assuming that prices hold in this range, we will start generating free cash flow next year while simultaneously continuing to materially increase our production. If you really look at the quarter and think about our differentiated growth project and our growth story, we are continuing to execute on our business plan. In my whole 52 years in business, other than making substantial acquisitions, I've never had this kind of growth profile of doubling production in 1 quarter. Please turn to page 4 of our investor presentation, and I'm just gonna pick out a few things on this page that'll give you insights as to where we're going and what's happening. Our legacy production averaged over 22,000 barrels a day. Of course, from the beginning of the year, in terms of our effective date on Hannathon, our total pro forma production averaged over 25,000 barrels a day. Actually almost 100%+ increase in production quarter-over-quarter. This continues our growth story. More importantly, we have 46 wells in progress right now of horizontal wells in various stages of drilling and completion. That is tremendous growth profile in terms of increasing our production as we go forward. We're doing all this on the basis of great operating margins. In addition to that, when you look at our acreage position, when we went public, we had 51,000 acres. Today, we've closed on over 97,000 acres, which is a 50% increase in the last year alone, and we have line of sight on acreage that we're still in the process of purchasing that's gonna take us well over 100,000 acres. The company is growing, we're getting more and more inventory, and we now have a split of contiguous net acreage, one of the largest 2 contiguous blocks in the Midland Basin, and it's roughly a 50/50 split between Flattop and Signal Peak. At the end of the quarter, we still have 6 rigs running, and we actually have the highest unhedged operating cash margin in the industry, way above any other companies. I wanna thank our bank group for their continued support and for the 3 new banks that joined our facility. We look forward to maintaining this relationship as we grow the company in the future. Now turn to slide 5. That gives you 4 different perspectives. It shows you our daily production growth, which is tremendous growth in terms of this particular quarter. We're gonna continue that as we go forward and looking forward to the rest of this year and into next year and throughout next year. We're gonna continue this growth profile, which is unprecedented in the industry. We've increased the number of wells that we're drilling. Our EBITDA, as we mentioned, is almost equal to all of last year's EBITDA in 1 quarter. On a fully unhedged basis is approaching $800 million. Our operational DUCs, I'm gonna spend a little time on that in the sense of people have asked, "How many wells are you turning in line?" When you have 6 rigs running, we now are gonna have approximately 30 to 35 wells that we'll be turning in line per quarter. We have about the same number of DUCs with 6 rigs. We're getting 10 to 12 DUCs also, which is another 30 to 35. That'll give you a sense of how our growth profile is gonna go and give you a sense of timing relative to our legacy production and how the new drilling rigs will start adding to this continued increase in growth production. Keeping in mind that production from our sixth rig that Hannathon had been operating will not start contributing until the Q4 of 2023. It takes time for these rigs to start contributing to production and start contributing to our EBITDA. Our successful program is gonna continue growing, and we're gonna continue with the highest operating margins in the industry and great production growth in a tight supply in the oil market. Our next slide on page 6 is just looking at the numbers on this. I'm not gonna spend a lot of time other than we're continuing to maintain 95% liquids. Our total BOE, including derivatives in terms of our realized pricing, is the highest in the industry. Our LOE is continuing to go down and will continue going down over the course of the next 60 to 90 days as we bring on all the benefits that we have been outlining to you going forward. Therefore, we also have the including hedges, the highest operating margin in the industry. We're turning on about 30 wells a month plus, and so we're very excited. The other thing that I think is important relative to LOE is that we now have about 70% of our generators online in that our pipeline system is starting to come in place, and we're adding that, and that reduces our generators as we go forward. Our LOE is coming down appropriately as a result of that. Mentioning again, HighPeak is an absolute differentiated growth story, and we're gonna continue taking advantage of current market conditions and pricing in order to create maximum value for our shareholders. With that, I'm gonna turn it over to Michael Hollis, who's gonna talk about operating margins and operations and bring everybody up to speed on the successful quarter that we've had. Michael? Thanks, Jack. Now turning to slide 7, HighPeak's differentiated margins. Again, not all BOEs are created equal. Slide 7 highlights HighPeak's continued unhedged peer-leading margins. Our Q2 2022 margins are 20% above our closest peer and 38% above our peer average. HighPeak is positioned to continue our margin expansion with our LOE reduction initiatives. For example, our removal of generators, electrifying our operations, and the expanded use of our recycling and company-owned SWD system. HighPeak will also benefit from the dilution of fixed cost as our production continues to increase. The main takeaway from slide 7 is production mix matters. It would take an average peer production of 35,000 BOE a day with their average margins to equate to the EBITDA that HighPeak generated in the Q2 with our margin per BOE over our 25,000 BOE per day on a pro forma basis. Combining our high margin oil-weighted mix with HighPeak's differentiated growth model emphasizes the potential for shareholder value creation through levered exposure to oil price and production growth. Now turning to slide 8. I'll provide a brief operational update on both Flattop and Signal Peak. In Flattop, we've added over 14,000 net acres contiguous with our block since the beginning of the year. We've already begun drilling a portion of the new acreage and are in the process of integrating the associated infrastructure with our legacy operations in the area. We commissioned our local HighPeak electrical substation in late May and are in the process of converting our field operations from rental generators over to more cost-efficient highline electrical power. To date, we've removed 70% of those generators in Flattop and should start to see the financial benefits show up in our LOE in the third and Q4 s. We have also plugged in one of our drilling rigs in Flattop to electrical power. At today's diesel cost, the anticipated cost savings are approximately $90,000 per well. We are on track to convert a second rig to grid power by the Q4. We initiated deliveries from our local sand mine partnership in late Q2 and are currently supplying one frac crew with local wet sand. We will continue to increase our utilization of local sand and expect to start servicing a second frac crew in late Q3 or early Q4. When fully utilized, HighPeak Energy will recognize roughly $300,000 per well in CapEx savings. Our crude gatherer is continuing to build out our in-field gathering system in Flattop and currently is gathering roughly 40% of our oil volumes via LACT units and pipelines. Our goal is to have the system fully operational before winter. We are also continuing to increase our use of recycled and non-potable water in our Flattop completion operations and are currently servicing 100% of stimulation fluids for two frac crews. Now moving to Signal Peak. As Jack mentioned, we closed on Hannathon acquisition late in the Q2, and we are currently in the process of integrating the properties and infrastructure in our field operations. We are also in the process of negotiating long-term gas and oil takeaway opportunities on the legacy Signal Peak area. With our recent positive well results, we do expect to receive very favorable pricing terms. The well results from our recent Wolfcamp A and Lower Spraberry wells continue to be positive and confirm the inventory in these two zones across the acquired acreage. It's reasonable to expect that we'll be drilling additional wells in these zones on the acquired acreage this year. We are active in Signal Peak with two rigs running and plan to turn in line 18 additional wells before the end of the year. We continue to be excited about this area and look forward to demonstrating additional success through the drill bit this year as we transition from the delineation phase to full manufacturing mode. Now turning to slide 9. ESG continues to be at the heart of every field level decision we make. As I mentioned earlier, we increased the use of recycled fluids that account for over 82% of Flattop stimulation fluids last quarter. We continue to reap major benefits from our water system, both on the CapEx and OpEx side of the equation, while drastically reducing our need for fresh water in our operations. We have removed, again, 70% of our generators at Flattop to date and are in the process of converting the remainder of the field to highline electrical power, reducing our emissions and costs associated with rental and fuel for the generators. We also converted 1 of our Flattop rigs to run off electrical power, and we expect to convert our second rig to highline power in the Q4. Our local sand mine partnership is now operational and is reducing our total truck miles to get sand to our completion locations. By utilizing wet sand, we also eliminate the combustion of natural gas needed to dry the typical frac sand, further reducing our emissions associated with our operations. We're gathering 40% of Flattop oil production, and this will greatly reduce the total number of truck miles and emissions associated with that trucking once the system is fully built out. We continue to have a flawless safety record. The health and well-being of employee base and our community is our absolute number one priority. I'll leave you with this. The vast majority of our ESG initiatives are both environmentally and fiscally rewarding to all of our stakeholders. If you turn now to slide 10. Mitigating capital cost escalation. I discussed this slide in detail on our Q1 call, and the main takeaway here is that management is constantly looking ahead to combat rising inflationary and supply chain pressures. As we've talked about all of these initiatives in the past, we're pleased to announce that we have implemented all of these items and are beginning to reap benefits associated with each. Again, we saw these pressures coming in advance and took serious preemptive steps to protect against these cost increases. One additional thing I'd like to point out here is that our local sand mine project is not only reducing cost and emissions, but is also increasing our operational efficiency. We are recognizing reduced downtime with sand deliveries now that we are supplying local wet sand due to the close proximity of mine to our field operations. We expect to increase our utilization of this wet sand in our completion operation as the mine continues to scale up into full scale operations. With that, I'll turn the call back over to Jack. Thanks, Mike. If you turn to slide 11, we've talked about these things before. Responsible growth, great operating margins, operational foresight, and maintaining flexibility. I've also had a lot of questions in terms of inventory, had questions regarding increasing with 6 rigs. Where are we gonna turn out? Everything we do is geared towards maintaining these four principles of having great operational foresight and operating margins and making sure we have a pristine balance sheet not going over 1x net debt to EBITDA. Our production cash flows are increasing significantly. We are very quickly approaching cash flow neutrality. In terms of thinking about the value of the company, whatever level of production we decide to grow the company in the next 12 months, somewhere between 65 and 80+ thousand barrels a day, at that point in time, we can literally go down almost 50% of budget and 50% less rigs running and still maintain in excess of $1 billion a year, possibly as high as $1.5 billion a year of operational free cash flow. We have two of the largest contiguous acreage positions in the Midland Basin with full spectrum operational synergies. We have one of the very best experienced teams to be able to execute and provide operational excellence. We will continue with our peer-leading margins, and actually, you can see from what Mike was telling you that we're improving on those margins. We are going to continue to innovatively adapt to market conditions as we plan for our future. We're gonna focus on our capital and operational excellence and lead our peers in cost structure. We're gonna monitor the market, and we truly, as a controlled company, have luxury that our competitors don't have. We are an operational differentiated growth story in that if oil prices go down, we can eliminate some of our drilling rigs and reduce our capital expenditures. As long as oil prices remain where they are today, it would be crazy with payouts happening as quickly as they are for us not to keep six rigs operating. One thing that people are thinking about is inventory. We have literally differentiated now over 50 rig life years, and that's almost 8.3. At six rigs running, that's 8.3 years of drilling activity. It doesn't matter what price you wanna use. It doesn't matter what projections you wanna use internally for production growth. If you take the ranges, you can literally look at $1.6 to 2+ billion next year, providing no excess spending, providing tremendous free cash flow, and providing great growth profile going forward. We have the inventory, we have the team, we have the financial capability to grow the business. You need to think about what's happening in the market. Where are prices gonna go? What's gonna happen to oil prices? Banks and lenders are always concerned about utilizing lower pricing, utilizing strip pricing on a reduced basis, all the way down now to almost $80 a barrel on the new 3-year strip pricing. If you think about that, the main precedent that I learned years ago working with the founder of OPEC and the Minister of Oil from Saudi Arabia for 24 years, that everything needs to be looked at on a macro scale. We have tremendous effective declines in production throughout the world on the basis of our decline curve. We have almost a 50% decline curve in the US. If we just stop drilling, we'd lose 50-something percent of our production in a year. We are only reinvesting, as an industry, about 30% of what's necessary just to maintain the deliverability. It's not a matter of if we're gonna have a recession, if we're going to continue growing production. It's a matter of it's not gonna happen with the industry and with the world's private wealth as well as nations, in effect, reinvesting only 30% of what's necessary to maintain production. We are going to have a shortage of oil and gas, and it's just a function of when that's gonna take place. Looking at HighPeak with the growth story we have, with the financial, and with the operation, and with the team we have, it's gonna be a very good place to be in terms of ownership, in terms of growth, and in terms of making money for our shareholders. With that, I'll turn it over to questions. Thank you. If you have a question at this time, please press star then one one on your telephone. Our first question comes from the line of Nicholas Pope with Seaport. Your line is open. Please go ahead. Morning, everyone. Morning. Morning. I was hoping you guys could update on Signal Peak a little bit more. I know you talked about in the prepared remarks. I guess in 1Q, I think we brought on 5 or 6 wells. I guess, were any brought on in the Q2? And also, what's kind of the longer-term profile relative to kind your expectations on that kind of basket of Signal Peak wells that came on earlier in the year? Mike, since Nick's question is more geared to operations, I'll let you answer that. Absolutely. Hey, Nick, thank you for the question. Absolutely. We've had the two rigs running constantly down in Signal Peak. You know, as with the rest of the company as a whole, we don't have anything other than operational DUCs. To that point, as we've been drilling wells in Signal Peak, we've been bringing them on, and we're pleased to announce that we've now got wells in the Wolfcamp D delineated all the way across both Hannathon to the west and HighPeak Legacy to the east, fully delineated across Signal Peak. We've been bringing on wells as we drill and complete them. We've had a couple wells come on this quarter in Signal Peak, and they come on looking very similar to the other wells that we had the quarter prior. Again, very pleased with our Wolfcamp D performance, as well as we've brought on a well on the very southern portion of our Signal Peak area that is performing the same, actually a little better than some of the wells to the north. Again, extremely pleased with the Wolfcamp D. We've mentioned the Lower Spraberry and Wolfcamp A wells, that we drilled kind a in the center of our Signal Peak pro forma block. Those wells we're extremely excited about. They are very similar in production profile to our Lower Spraberry and Wolfcamp A up at Flattop. As you know, the economics there are fantastic. I think it would be reasonable to expect we're gonna drill several wells, out of the 18 the rest of this year that'll be turned online. Some of the wells we drill this year will be turned online in 2023. Between now and the end of the year, we will drill some additional Lower Spraberrys and as down in Signal Peak. Got it. That's helpful. Also, Nick, I'll add a little bit to what Mike said. From a geological perspective, almost half of our acreage to the west has the Wolfcamp A and the Lower Spraberry in terms of locations. If you refer to the appendix, you can see how many locations we have in terms of developing that area, not only in the Wolfcamp A and the Lower Spraberry, but also considerable number of locations in the Wolfcamp B, and we'll be delineating that further throughout the next 12 months. It's turning out great. We're very excited about it and, of course, very pleased about increasing our acreage position in that area. Excellent. Kinda looking at a little bit at the big picture from production. The previous guidance y'all given after the Hannathon announcement, I think was kind a mid-30s for barrels of oil production for the year. It seems like a pretty big uptick for the H2 of the year. Is that I mean, are you all still comfortable with the targets that with the exit rate that I think y'all have given for 2022 and that full-year production guidance kind a with where production is and kind a where y'all expect to be with these you know large number of wells coming on in the H2 of the year? Yeah. We both, Mike and I, will visit on this particular question a little bit and respond to it. We of course have not changed our guidance, and we're very excited. It all depends on how much interference we have across our entire block with as we're fracking additional wells. We definitely are going to have a growth, and you use mid-thirties in by the end of the year. We're we think that we'll be a much better number than that. We are excited about keep maintaining our growth production growth profile going forward. We'll continue with 6 rigs drilling to continue that growth profile. If anything, relative to looking at the past is also gonna happen in the future, doubling production in a quarter, I don't think we're gonna have that kind of growth, but we'll be very, very much on par with what we are projecting. Mike, go ahead. You bet, Nick. Yeah, your number of, you know, the kind of mid-30s there, that's an average for the year, and that is pro forma Hannathon with an effective date of January 1. Just keep that in mind when you're looking at that average number. Now, exit numbers, you know. Again, we closed that, so the production volumes you will start seeing basically in third and Q4. That is part of that step-up jump that you're talking about. Then also on slide 5, you'll see a large number of wells that are kind of in progress to be turned in line. As you go forward in time, kind of an average run rate for HighPeak running the 6 rigs will be roughly 30 to 33 wells a quarter. You can see a big number of those 10 were turned in line, kind of mid-July. To answer that question, yes, as we picked up activity over the last couple quarters, going from 2 to 4 to now 6 rigs, yes, we will have a large number of wells coming online toward the end of the year and a large production response associated with that. Year-end kind of exit rates are gonna be very similar to what we put out as guidance. Again, your numbers are pretty close there. On a run rate, you know, Jack had mentioned kind of interference from offset stimulations that we're doing. Again, as you pick up activity, obviously you affect more wells as you pick up frac crews and start fracking additional pads. The good news is we've been running our three frac crews for quite some time now, so that effect is immediate. When you pick the fracker up and start fracking, it affects, you know, roughly within about a week of starting that. Our run rate going forward has that offset kind of baked into it going forward and in those projected numbers. Thank you. Our next question comes from the line of Jeff Robertson with Water Tower Research. Your line is open. Please go ahead. Good morning, Jack and Mike. Can you, Jack or and/or Mike, just a question on the 6-rig pace. How does the decision around pad sizes play into how you look at production and also the effect of interference when you bring wells online? From a macro perspective, and I'll let Mike go into more detail if he wants to, Jeff, if it doesn't answer your question. From a macro perspective, we do not try to run the business on the basis of worrying about shutting in production. We do what's necessary relative to the reservoir and relative to proper growth, proper maintenance and proper care of the reservoir. On any given day, as Mike's saying, we might have as much as 6,000 barrels a day with numerous offset wells shut in as we drill. Undoubtedly, drilling pads and multiple wells on a pad is much more commercial, much more, much cheaper from an operational perspective. As you can tell, we really focus on our profit margin, and most of our decisions are made to protect the reservoir and not necessarily worry about production growth. We are gonna have some lumpiness at times. Some quarters are not gonna grow as fast. If you look at our past, we've literally had quarters that went down on production. Then all of a sudden, we get wells back online, and all of a sudden, our production is much higher than what we projected. It's not really a conscious decision other than proper maintenance of the reservoir and protecting and getting the best frac and the best proppant in place. Mike, anything else you wanna add? You bet. No, Jack, you covered it very well. Hey, Jeff, you know, to your question about the 6 rigs and the frac crews, you know, we feel very confident that 6 is the right number for HighPeak today. The capital split that we have of 4 rigs running up in Flat Top and 2 down in Signal Peak seems to be, again, based on 100 different variables. You know, probably the biggest one for Signal Peak is we want to make sure that we have the infrastructure in place to be very efficient and moving into a development plan and mode down in Signal. Running the 2 rigs down there is the most efficient today. Now up in Flat Top, your question about the number of wells per pad, obviously, there's competing things on either side. We'd love to be able to do as many wells per pad as possible. To your point earlier, timing is important. It does take time to drill and complete each additional well as you do bigger and bigger pads. We have to be mindful of how much capital we deploy into an investment before we start receiving returns. Again, there are some competing factors, but we do feel like we've got the most optimal for where we sit today. You know, as Jack mentioned, yes, we do have some, you know, every company does lumpiness in production growth. Now, in the past, when your base volume was smaller and you were adding frac crews, you saw much larger percentage changes in that kind of lumpiness. Now, from a forward-looking basis, our base production has grown significantly. As I mentioned before, we have the 3 frac crews running. Now, as you move from one pad to another, there will be small lumpiness, but going forward, production will continue to increase each quarter. It may not increase by, you know, 100%. You know, it's gonna be quarters where it's a couple thousand a day. In other quarters, it's 10+ thousand a day in a quarter. It's going to be up and to the right. The lumpiness going forward will hopefully not be any lumpiness down because, again, the base is so large, and we already have kind of an equilibrium amount of frac impact that we'll just live with those 3 frac crews as we go through time. Again, think up and to the right, and that lumpiness will just be a little bit of flattening of that, you know, that kind of up into the right curve. Hopefully, that helps, Jeff. That does. A question, moving to margins, you obviously have some of the strongest margins in the group in the industry. Mike, can you talk more specifically about the impact that the highline moving the generators off in Flat Top could have on Q3 and Q4 LOE now that they're the substation's fully operational? You bet, Jeff. You know, today we've got, again, the 70% of the generators removed and on highline power. Going through Q3 into Q4, we'll continue to remove the rest of them. Again, it takes a little time to run the highline power lines out to the locations. So, kind of look for that full-blown effect in the Q4. Q3, again, you've got about 70% of it. Generators locally in the field are an extremely expensive operation. One, you have to rent the units. They don't run at a very high efficiency, and then you have to supply fuel. As everyone knows, depending on the fuel that you use, whether it's liquefied petroleum gas or it's CNG or even diesel at the worst, it's all extremely expensive. It's an order of magnitude cheaper to go off of highline power. If we look into Q3 into Q4, you would see roughly. Our volumes are increasing as well as we grow into third and Q4. On an individual BOE basis, you're looking somewhere in the $1.25 in the Q3 and something a little north of that, closer to the $1.50s range in Q4 for total BOE difference. Remember, as our production grows, so too decreases our fixed cost. G&A is continuing to level out at a $1 a BOE or less. We've added these acquisitions, grown production, and not added a lot of staff. We've got a very competent staff that's able to scale. Again, we do see this margin expanding, and appreciate you saying and pointing out that it is an industry-leading margin for BOE. We're very proud of that and blessed to be in the right spot that provides a very, very oily mix. Thanks, Mike. Turning to CapEx, you all outlined in the press release that highline power on the one rig will save you about $90,000 per well, and I think sand, with the wet sand, will save about $300,000 per well. You also talked about servicing one crew with recycled water. Can you talk about what that will save on a, maybe on a per well basis? You bet, Jeff. Yeah, it's. We can do two frac crews now fairly close with just recycled fluid. We supplement that recycled fluid with non-potable water from the Santa Rosa field. Both of those have very similar cost structures. When you look at whether we use one or the other, we kind a look at those as virtually the same. They do offset bringing in fresh water from local farmers and folks that need that fresh water to take care of crops and/or livestock. However, you mentioned a very good point. There is a huge difference in cost between supplying your stimulation needs with fresh water or what we're doing here at HighPeak with recycled and non-potable water. There's roughly a $200,000 a well difference in CapEx cost just for the stimulation fluid side. Again, as you mentioned, the sand and being able to recycle on the LOE side as well, seeing those savings. We look at that equation holistically. We wanna attack all sides of it. A great realized price which we've gotten, again, from location, being close to the refinery and close to gas plants, putting the infrastructure in place such that we can acquire that great realized price. Again, with that infrastructure and looking forward and making sure we have all of these initiatives in place, reduce our CapEx and OpEx, giving us a very high recycle ratio for this HighPeak machine that's been built. Thanks. I'll go back in the queue and see if somebody else has a question. All right. Thanks, Jeff. Thank you. I'm showing no further questions at this time, and I would like to hand the conference back over to CEO Jack Hightower for any further remarks. Well, I just would like to say that everything is going along the way we had planned it. Our production is increasing, our costs are going down, and we'll continue with the efficiencies that Mike just outlined with Jeff. We are very, very pleased with market conditions. Nobody likes to have a decline in production, I mean, in oil prices like we've had over the course of the last two months, but that can't stay very long. We will have times when oil prices go down. We will continue to always have volatility in the market. On the whole, oil prices are gonna continue going up and to the right over the course of the next year to year and a half, and our production's gonna continue going up and to the right, and our operational efficiency is gonna continue to become better and better and lower cost, lower G&A, lower lifting costs with LOE. We're extremely pleased with what's taking place, and we appreciate the support of the shareholders. Honestly, I think we're trading at a market price below what our peers are trading for. When you have production growth of doubling in effect in one quarter, the market ought to start recognizing that this growth is gonna continue, and our stock price should start reflecting that growth. Thank you very much. This concludes today's conference call. Thank you for participating. You may now disconnect. Everyone, have a great day.