HighPeak Energy, Inc.

Good morning, everyone. And thank you for standing by. And welcome to the High Peak Energy 2021 Second Corner 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 the session, you'll need to press star 1 on your telephone. Please be advised that today's conference is being recorded. If you require any further assistance, please press star 0. I would now like to hand the conference over to your speaker today, Stephen Solon, Chief Financial Officer. Please go ahead.

Thank you, Norma. Good morning, everyone, and welcome to High Peak Energy's second quarter 2021 conference call. Representing High Peak today are Chairman and CEO Jack Hightower and President Michael Hollis. During today's call, we will make reference to our August investor presentation and our second quarter 2021 earnings release, which can be found on High Peak's website at www.highpeakenergy.com. 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, which was issued Monday afternoon. I will now turn the call over to Chairman and CEO, Jack Hightower.

Thank you, Stephen. Good morning, everyone, and welcome to today's call. As expected, our second quarter proved to be another successful quarter for High Peak, and this is evidenced by our continued positive well results, capital efficiency, and high operating margins. Our production increased. And our EBIDACs increased over 90% quarter over quarter. Our liquids-rich production stream of 90% oil and 96% liquids continues to differentiate us from our peers and will continue in the future. Our barrel of oil equivalent is much more valuable and results in these higher profit margins. We currently have multiple wells that are in the early stages of flow back. And in addition, we recently added a second rig, which will further accelerate our growth profile into 2022. We are definitely a growth company, as will be evident after our presentation and discussing our plans into the future. I'd like you to refer to the highlights in the press release and then turn to slide three of our August investor presentation. This slide, along with our discussion, will emphasize and further discuss the highlights that we outlined in our press release. Our second quarter, we focused very much on fiscal responsibility and production growth and high operating margins. As mentioned in the press release, we averaged over 8,800 barrels of oil equivalent per day up 66% from our average in quarter one production. We have multiple wells that are in early stages of flow back, and as these wells ramp up and other wells come online, we expect our production to continue going forward. We picked up our second rig in early third quarter, and the addition of the second rig will accelerate our growth profile going into early 2022. Our high Our contiguous acreage position, our high percent of operated properties allows us to control our own destiny, which is very important in today's business climate. We effectuated some acreage swaps during the second quarter, which also increased our percentage of operated properties. In addition, we made multiple acquisitions or we will be in the process of closing those acquisitions that will add approximately 6,200 net acres to our acreage position. And our production from these acquisitions will add up to almost 1,400 barrels a day for the remainder of the year, the remainder of 2021, which is not included in our guidance as we discuss that later on. We expect to close these acquisitions in the third quarter. It'll increase our working interest in some of our operating units, and with our high oil cut and our expertise, contribute to our leading all-in costs in full cycle economics. Our second quarter price realized an average price of $60.40 a barrel equivalent, and our operating cash margin was $51.35 per BOE. Both of these Realized price and cash operating margins are peer leading. So we're extremely excited about our capital efficiency and what's going on. And I'll refer now to slide four in the presentation. We are continuing to deliver capital efficient oil weighted growth. Our production increased 66%. in effect compared to our first quarter from 8,800 barrels versus 5,300 barrels in the first quarter. Our EBITDA went up from almost 91% to $38.4 million. That was a 91% increase, as mentioned. Our production stream of 90% oil and 96% liquids drives our high margins. And as mentioned before, these are peer-leading numbers, and it gives us different BOEs and more valuable income than our peers have with the same amount of production. We also increased our lateral feet drilled quarter over quarter almost 40%, and that's a tribute to our drilling and operations team being able to do that. So we're drilling faster. and we're drilling more efficient wells. And this allows us to have more exposure to the reservoirs. Our balance sheet continues to stay strong, as evidenced by our small amount of debt. In fact, our net debt is only $1.2 million. And of course, we have $120-something million borrowing base. And I'll refer to that a little bit later. As we go into slide four, Some of our key metrics there are we have realized prices of $60.40, which I mentioned, 92% of WTI index on an unhedged basis. That is absolutely peer leading and phenomenal relative to some of our other peers. Our hedged BOE price was still $59.10 a barrel, which is also extremely high compared to our peers. Our hedged barrels are at $62 a barrel through the second quarter of 2022, and this represents less than 50% of our forecasted oil production, giving us good exposure to strong oil prices. Our cash margin in the second quarter was 75% of the oil and gas WTI index. Again, this is higher than any of our peers, and we're extremely excited about that. Our cash G&A decreased by over 45% this quarter, and that helps us drive high operating margins. We have a very efficient organization. Our CAPEX in the first quarter totaled $46.8 million, and $44 million of that was related to DC ENF costs. And we always include, for full transparency, our equipment costs, our facility costs, and our water handling costs for the first six months. We drilled 106,400 feet of lateral feet, not including two horizontal wells. our two horizontal saltwater disposal wells. And our average daily production was up over 300% during the last four quarters. So as mentioned, we are a growth company, and we expect to continue that growth as we go forward. And we have the 5,000 barrels a day hedged, which is at a price of approximately $62 a barrel through the first quarter of 22. Now I'm going to turn the program over to Mike Hollis, who is our president, and he's going to talk more about our capital efficiency and our operations.

Thanks, Jack. I'd like to start by thanking our organization and let them know how proud I am for accomplishing so much in such a short time. We've made great progress on our key objectives of operating in capital efficiency, maintaining our impeccable safety records, all while rapidly increasing our production. With our marketing agreements, power upgrades and solar initiatives, recycling, and sourcing of local sand, we are attacking all sides of the efficiency equation, receiving higher realized prices while reducing our CapEx and OpEx, and achieving all this while advancing our ESG goals. If you'll turn to slide six with me, the capital efficiencies, We've maintained consistent capital efficiency over the past three-plus quarters, despite recent inflationary pressures. Since IPO, we have dramatically reduced our dollar-per-foot cost, and we continue to achieve approximately $505 a foot, all in D, C, E, and F costs. We've increased average lateral links to roughly 13,000 feet, These longer wells are more capably efficient, and we also have the benefit of large acreage positions allowing for optimized field development. Our drilling team is always making improvements on our drilling metrics. Since IPO, we are reaching TD 33% faster on much longer wells. Our goal is to keep our DC ENF cost per foot relatively flat as we move into this more active upstream environment. High Peak began recycling produced fluids in the second quarter on our most recent four-well pad. We're excited to report that we were able to use up to 85% produced fluid on several stages. This reduced our cost and need for any makeup fluid. We also plan to source local sand mines to minimize transportation costs, which also have major ESG benefits of reducing emissions and infield truck traffic. Our second rig will primarily be focused on drilling infill multi-well pads, allowing us to optimize production while increasing pad efficiency. Our flat-top well economics continue to be strong. 12,500-foot Wolf Camp A wells pay out in less than seven months at $70 oil and still pay out in less than a year at $50 oil. Our lower sprayberry well economics continue to be compelling as well. If you'll turn with me to slide seven, operational efficiency and margins. Here's another large differentiating factor that makes High Peak compelling. As Jack mentioned earlier, our roughly 8,800 BOE a day is different. Moving from left to right on this slide, our BOE is 96% liquids, and 90% of that's oil, or 90% oil. Making our BOE inherently more valuable per unit because of that oil cut and liquid cut. And as you can see in the center chart, our all-in cash costs continue to decrease. Because our BOE is worth more per unit and the cost to produce that BOE continues to trend down, this equates to High Peak having the highest cash margin per BOE amongst our peer group. The chart to the right shows High Peak's second quarter results. Our revenue per BOE for the second quarter was $60.95, This is 25 percent higher than our next closest peer and significantly higher than the average. High Peak's cash margin for second quarter was $49.32 per BOE. This is 32 percent higher than our next closest peer. High Peak's company-owned infrastructure continues to positively impact our economics now and will more so as we move into the future. If you'll turn to slide eight, high peak infrastructure update. Phase one and two of our company-owned and operated produced fluid system is now operational. This will provide for cost-efficient fluid disposal and increased recycling capability, which will have the benefit of reducing our OPEX as well as our CAPEX. As mentioned before, High Peak has began utilizing produced fluids for our completion operations in late Q2. Our second Horizontal Ellenberger SWD is now drilled and should be operational here very soon. High Peak signed a long-term crude oil gathering and purchasing agreement in the second quarter. This agreement provides for attractive all-in rates. The gatherer is required to install and operate the system. This project will increase our realized price and decrease any infill truck traffic. High Peak also signed a replacement gas contract for our flat-top production. This provides for improved natural gas and NGL pricing. The gatherer will expand the low-pressure gathering system, eliminating the need for infill compression, reduced flaring, and greenhouse gas emissions once operational. If you turn now to slide nine, ESG highlights. It's a testament to High Peak's experienced team and ingenuity that we are, I feel, years ahead of any company our size on ESG initiatives. This is nothing new to our team. We will continue to lean into this movement, always striving to be an ESG leader, and look forward to providing future updates on our progress. Again, High Peak started recycling produced fluid in the second quarter, and we have plans to continue to increase that percent recycle used over time. We have entered into agreements for substantial electrical upgrades to increase field electrification. This will reduce emissions and the need for generators in the future and give us the ability to run rigs off high-line power. In the second quarter, we also signed an agreement for a 13-megawatt solar farm, which over the life of the contract will result in a reduction of roughly 100,000 metric tons of CO2, essentially High Peak will be using solar power to drill and operate many of our wells. We've had zero safety incidents reported to date. High Peak continues to be a very active player in our local operating community. We've also recently joined the environmental partnership and continue to provide our employees with flexible work environment in this post-COVID world. With my comments now complete, I'll turn the call back over to Jack to discuss our updated capital guidance.

Thanks, Mike. As you can see, looking at our operational overview, it's been a very successful quarter for us, and we've laid the groundwork for many plans going forward into the future. We're going to be focused on future growth. We're increasing our capital investment guidance due to picking up the second rig and drilling faster and more efficient wells. We've updated our DCENF capital guidance where we're increasing our midpoint is about $217 million. This will allow us to drill approximately 35 to 40 gross wells. And our infrastructure guidance updated to $40 million at the midpoint. Most of these increased expenditures are due to picking up the second rig and accelerating projects into 2021. Our second rig will be focused mainly on drilling infill locations, utilizing multi-well pads, and that will help us have responsible development to maximize our reservoir performance and optimize our efficiencies. One thing that I want to recognize here is as we start drilling closer in development wells, we will have a little lumpier production going forward. And the best way to explain that is that multi-pad development, when we are offsetting producing wells, we will have to shut in those wells so that we don't damage or cause any issues with our reservoir. So it helps us to manage the reservoir more effectively And so for the next few quarters, as we're growing with the two rigs versus one rig, we will have lumpier production. But our overall growth path will remain the same. And we should continue increasing proportionately the way we've been increasing our production over the last four quarters. But what this does, it sets the stage for tremendous robust production increases and growth in 2022. So turning to slide 11 now, to summarize our company highlights in the second quarter, we had very responsible growth of over 66% quarter over quarter. We have more production growth on the way with our second rig being added. We have a strong balance sheet. In fact, our net debt is only $1.2 million. We increased our borrowing base to $125 million. We initiated a dividend project so that we're fully aligned with our shareholders. And we expect to be able to continue that, even though we have a little bit of a negative in terms of cash flow versus drilling expenses. We're going to keep a very strong balance sheet going forward, and we'll expect to keep our debt less than one times debt to EBITDA. Great operational excellence with our team is focused on capital and operating efficiencies, and I think you can see that going forward, as Mike mentioned, we expect to keep our costs in line even with inflation pressures that are taking place. We're putting these measures in place constantly to keep our costs low and be peer leading in terms of efficiencies. Most importantly, though, we have the best product mix in the industry with 90% oil, 96% liquids. This drives not only superior profit margins, but allows us to get our money back very quickly compared to our peers as we expand our capital budget. So we have great realized pricing. We have high oil cuts and low costs. and great well economics. So as you can see, we had another great successful quarter for High Peak. We generated positive earnings and almost doubling our EBITDA. We kept our balance sheet strong. And I continue to be extremely proud of our organization. Everybody is working hard. Everybody is working efficiently. focused on responsible growth, and we have set the stage for great things in the future. And with that, I'd like to open up the call for any questions anybody might have.

Thank you. Thank you. At this time, as a reminder, to ask a question, you'll need to press star 1 on your telephone. To withdraw your question, please press the pound key. Please stand by while we compile the Q&A roster. Our first question comes from Neil Dingman with Truist Securities. Your line is now open.

Morning, guys. Thanks for all the details. Jack, I'm just wondering more sort of overall big picture of your philosophy going forward. Once you have, you know, the growth has sort of stabilized and, you know, let's say, I don't know, down the road a few quarters from now, your philosophy between sort of growth and obviously there's a, you know, I'd say obviously the topic is really these days obviously the shareholder return. So how do you think about balancing those?

That's a great question, Neil. One of the things that I think about in terms of future and looking down the road is we generally try to balance. We always want to maintain a low leverage situation. We understand leverage, but With volatility in the market, we don't want to get ourselves in trouble like some of our peers have done in the past. So we're going to maintain that. But we have a 10-year inventory of... drilling locations. And so as oil prices stabilize and as we increase our production, very quickly we will be in a situation where we'll have excess cash flow. Historically, we have always balanced our growth profile with acquisitions as well as through the drill bit. But we don't have to make an acquisition. We're not going to delude ourselves unnecessarily. So unless something is very accretive, i.e. the recent acquisitions that we're making, we're not going to need to worry about growing the company. We have enough locations internally right now to have very effective growth for the next five to ten years. Hopefully that answers your question.

Yeah, no, great details. And maybe one for Mike. Just, you know, I like that you've talked and you give a lot of good details. I'm just wondering, Mike, what is the typical time needed on the flow back to see more of a peak production? And I'm just wondering, once you get to that area, could you maybe talk about the continuous pressure and all once that, you know, they've hit this point?

Yeah, Neil, typically, you know, wells up in our northern area from the The day we put them on pump, and these wells typically go on the ESP day one. Now our wells to the south in Signal Peak, like the Wolf Camp D, those will flow naturally for a period of time. But back to flat top on our Wolf A and Lower Sprayberry, it varies a little, but typically it takes about a month from the time you put it on flow back to reach kind of your peak production level. And again, a lot of these longer wells that we have, it'll stay at, quote, peak production for a period of time because you may be pump limited on being able to move enough fluid. So it'll stay at that level pretty well flat for several months, and then it may start its initial decline. And in our area, again, it's a little less decline than what you would have in the center part of the basin. We've got a slightly higher overall perm in our reservoir. And again, Neil, it changes a little between the A and the lower spray vary. And it depends also on how many wells you put into an area at one time. A single well by itself takes a little longer to clean up. When you do a large multi-well pad where we can get several pumps on at one time, and we've, especially in a more mature area where we can turn the offset wells on at the same time, you can get some of these oil and peak rates a little quicker in the future. So, Again, it's a little different than in the center part of the basin, but not that different. Again, a couple weeks longer. Great. Thank you both for your time. You bet. Thank you, Neal.

Thank you. And our next question comes from John White with Roth Capital. Your line is open.

Congratulations on a strong quarter, and thanks for taking my question. You're welcome.

Thank you, John.

In the press release, Jack commented, you have multiple wells that are in early stages of flow back. Does that include all of the 10 wells that were completed during the second quarter?

Yes, Mike, if you want to further elaborate on that.

Yeah, sure. Yeah, John, look, in any, especially as we picked up the second rig, right, there's a natural number of what we call operational ducts that follow behind follow behind your rig, especially as we're doing multi-well pads. So of the 10 wells that were completed in the quarter, roughly the first five to six of those have kind of began to reach peak production or cleaned up very significantly. The last four to five wells are kind of in that initial cleanup period because they were closer to the end portion of the quarter. And that kind of number and rate cadence will follow the rigs more or less forever, moving a couple wells in or out from the operational kind of lag behind a rig. So nothing there that was indicated any different than what we would expect with having more wells cleaning up or taking longer. It's just literally the normal cadence behind the rigs.

Okay. Thanks very much. And the two wells in Signal Peak you want to offer your comments on your expectations for those wells or how they compare?

Yeah, we're very excited about both of those wells, John. The Wolf D well is presently making right at 1,000 BOE equivalent and doing very well compared to the wells to the west of us that created the the immediate movement into this formation. We do feel like we can even improve on those wells as we go forward, but we're excited about that. And of course, economically, They have a little bit higher gas-oil ratio than some of our wells up north. However, the operating expenses and the ability to get them online faster is much more efficient in terms of going forward down there. So we're excited about that. The other well, the Wolf Sea well, it's so early in its stages right now. It's It's at about a DOE equivalent of 400 barrels a day, cleaning up. And we're very excited, but it's too early yet. We need more time yet. And it's also a short lateral well. We only drilled that well 7,500 feet out in terms of the lateral. We could improve on that significantly by going to 12,500 foot lateral, as well as we'll get more information as we go forward in terms of how to complete the wells. And we're learning every day more and more about that formation, but it's very encouraging at this stage.

Thanks for those details. And just one last brief question. The mix of drilling for the balance of the year, that will remain focused on flat top. Is that correct?

Yes, definitely. We're thinking maybe less than 5% to 10% of our wells will be drilled down at Signal Peak. Most of our drilling will be up at flat top.

All right. Thanks very much. I'll pass it back to the operator. Thank you.

Thank you. And our next question comes from Jeff Robertson with Water Tower Research. Your line is open.

Thank you. Mike, on some of the initiatives you all have to control operating costs, can you quantify in terms of dollars per BOE what kind of savings you anticipate with sand and recycled water and also as you electrify in 2022?

You bet, Jeff. And a couple of those Really, the dollar per BOE may be really just on the electrification side. The other pieces are more on the capex, so it would be more the dollar per completed foot that we'll see. I'll run through a couple of them for you. The local sand, recent other public company announcements are very indicative of what we're going to see. It'll be late 4Q, early 1Q when the sand mine will be operational and we'll start taking that wet sand. But as you saw from the guys that are very close to us up at Flat Top, they have several mines. two other public companies, and their announcements a quarter or two ago was about $90,000 per well that they were saving. This quarter, as fuel costs have gone up and trucking's gone up and sand cost has gone up, they're now showing about a $200,000 per well savings, and I think that's pretty representative, Jeff, of what we're going to see. As we continue on to produce fluid, utilizing that in recycling versus buying fresh or Santa Rosa water from local aquifers. One, it's a huge ESG benefit. We absolutely don't want to utilize any more water from reservoirs that are usable for farmers or for folks to drink. We want to be able to recycle everything we have. There is a fairly large capital savings there, cost per barrel to purchase, fluid is typically in the 50 cent range and you have to transport it. Here, our SWD line runs right down the path of our surface location, so it greatly reduces the cost of transporting the fluid, as well as the fluid virtually has no cost other than a little bit of treating that we have to do going through a tank prior to going into a frag job. On the electrification piece, from an LOE standpoint on a dollar per barrel kind of lifting cost, over the next couple quarters, until we get the substation energized and the solar farm tied in, we will see generators, and we've taken the step of going out and building what we call microgrids, where we have a bank of generators that are more efficient than single generators. So going forward, you'll see those costs from generation out in the field over the next couple quarters, but then you'll see a dramatic drop as we go to high line power. Rough numbers for that for you, Jeff. If you're generating your own power, you're in the... $0.40 range per kilowatt versus when you buy it off a high line power, you're in the $0.03 range. It's a huge savings, not only from an emission standpoint, but as well from a cost standpoint. So you'll see a dramatic change in 2022 of our lifting costs. And when we do that, we've got enough spare capacity on our system such that we'll be able to run and operate our drilling rigs off a high line power, again reducing the need for fuel, diesel, and CNG as some of our rigs are dual fuel capable. So we've got a lot of initiatives in place. We're turning every knob that we see out there that's easily available. We're always turning over every rock we can to try to find the next thing that can help us both on a call standpoint as well as our environmental footprint.

Thank you for that. Jack or Mike, on the acquisitions or on the acreage acquisitions, can you talk about where in the life of the production is, the 1,400 BOE a day you're buying, and also does that commodity mix, is it very similar to what you're currently producing?

Yeah, it's very similar. Of course, there were multiple acquisitions, in excess of four acquisitions, and some trades involved in that whole scenario. And some of the acreage and some of the acquisition involved the 90% to 96% oil, and some involved lesser oil cut, but still staying in the 70% range, and with lower LOE expenses. plus that high of an oil cut compared to our peers, our profit margins will stay about the same in terms of our development, our payouts, and our cash flow on a net basis. So we're really excited about that and going forward with the acquisitions we've made thus far. They were very accretive to us, both from an acreage perspective and from a development perspective, and from a control perspective of being able to control our own destiny and not having to deal with non-op interests in terms of drilling our wells efficiently and timely.

So is it fair to think, Jack, that some of those barrels are essentially added without really adding any costs since you already own working interest in some of it?

Yeah, that is a good way to look at it. There's no question that since we already had working interest, of course, we're picking up the costs associated with that interest, but yet economically we made the acquisitions in a very accretive manner. So we'll get our money back very quickly and add to our approved as well as development opportunities.

Great. Thank you very much. Thank you.

Thank you. And I have a follow-up question from John White with Roth Capital. Your line is open.

That was an excellent amount of detail on the effect of your infrastructure work and how it will reduce your OE. Following on to your crude oil gathering and takeaway work, Should we be looking and maybe give us some timeframe for a decreased crude oil price differential?

Go ahead, Mike.

You bet, John. Yeah, so the deal that we've done with DELIC, you know, we're going to begin, you know, we're doing right away and beginning to, we've got all the pipe, everything purchased, getting ready to start construction. But with the agreement we have in third quarter, we will go from what used to be a trucking rate, which was somewhere in the $1.40-ish range for trucking those barrels to market. We're going to an all-in number that's, you know, 70-some-odd cents lower than that in that range. And that'll be for the barrels up in flat top. So we will see a market change to our realized price. And again, that's a all-in marketing kind of gathering fee as opposed to those kind of numbers being half of what some of our peers would typically have to pay for either marketing and or the transportation fee. So again, it's a large change to our realized price. And to that point, our gas gathering system is about in the same stage right away pipes been purchased and we're about to start turning dirt over so that we can get those pipes installed. And with that change, again, that's going to come closer into the end of fourth quarter. We'll start to see the changes in pricing on our NGLs as well as our gas. Again, it's just One, we get to sell all of the gas we produce, where today we're starting to get tight on some of our infilled low-pressure gathering that's out there. So we saw this coming multiple months or a year or so ahead of time, got with our marketing department, got with plants nearby, got the plan put in place, and are going to have our new system built and ready for all of our future development in Flat Top. again, so that we can reduce any fugitive emissions. And to take it a step farther, as we built out our infrastructure in Flat Top, both on the oil and gas side, what we've done is very, I say very large, but large central tank batteries such that we only have around nine tank batteries today that will service the vast majority of what we drill over the next several years in Flat Top. So having those central tank batteries, we've already gone in and put in our what's called vapor recovery towers, vapor recovery units, so that we can reduce our fugitive emissions that you would typically have from a small tank battery that would be a permit by rule battery. So again, we're trying to get in front, build a system that's scalable, expandable, and Most of that capital has already been spent, so we no longer have to build batteries for wells when we go put an additional two or three wells out to the east or west of where our development currently sits. All we have to do is upgrade that tank battery at a much cheaper F cost than that DCE and F piece. So again, with all of those initiatives, all of that pre-planning, and it's coming together in fruition right at the time that the industry is getting very active and we're seeing prices for individual pieces, fuel, and people beginning to move, we will be able to see and take advantage of all of that work that we've done prior to keep our cost in line and further differentiate us from all of our peers in the public market.

And John, just to further add to what Mike said, Beginning with your first part of your question, as you can see, this will definitely lower our differential and increase our profit margins. And these investment dollars that we've spent, most of which are being spent by the purchasers, are going to be great return on investment dollars and lower and give us higher profits going into the future.

Thank you. It all sounds very positive. And just to confirm, Mike, did you say that you had completed the second SWD well?

Yes, sir. The second SWD well is drilled. And, you know, again, with an SWD, there's not a whole lot of completion that has to happen. We go and run tubing, stimulate the well slightly, and then start injection. So we've got the battery built. So we're talking within... weeks, we'll have that well operational.

Thanks again. I'll pass it along.

You bet. Thanks, John.

Thank you. And at this time, I'm showing no further questions in the queue. I'd like to hand the conference back over to Mr. Jack Hightower for any closing remarks.

Yes, thank you very much. We're glad to have had everybody attend and learn more about your company and what we're doing. As the CEO of the company, I can't be more excited about what's going on. The progress we've made and continue to make is really unprecedented in our industry, and we look forward to continuing our growth profile and continuing our success and continuing hope that oil and gas prices stay up so our profits can stay like they are. We're in excess of 200% internal rate of return now on the wells we're drilling. We know our reservoirs now. We've pretty much concluded that almost all of our acreage is prospective. And now it's just a function of developing this acreage in a prudent way, and we're off to a great start. So thank you for your support and your participation.

This concludes today's conference call. Thank you for your participation. You may now disconnect. Everyone have a wonderful day.