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Highpeak Energy Inc
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Thank you for standing by, and welcome to the First Quarter 2022 HighPeak Energy Conference Call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question-and-answer session. [Operator Instructions] As a reminder, today’s program may be recorded.
And now, I’d like to introduce you host for today’s program, Mr. Steven Tholen, Chief Financial Officer. Please go ahead, sir.
Thank you and good morning, everyone, and welcome to HighPeak Energy’s first quarter 2022 conference call. Representing HighPeak 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 reference to our May Investor Presentation, our first quarter 2022 earnings release, and Form 10-Q, which can be found on HighPeak’s website.
Today’s call participants may make certain forward-looking statements relating to the company’s financial condition, results of operations, expectations, plans, goals, assumptions, and future performance. So please refer to the cautionary information regarding forward-looking statements and related risks in the company’s SEC filings, including the fact that actual results may differ materially from our expectations due to a variety of reasons, many of which are beyond our control.
We will also refer to certain non-GAAP financial measures on today’s call. So please see the reconciliations in the earnings release, which was issued Monday afternoon. Our prepared remarks will begin on slide four of our May Investor Presentation.
I will now turn the call over to our Chairman and CEO, Jack Hightower.
Thank you, Steven, and good morning to everyone, our investors and stakeholders, as well as analysts and other interested parties. This is, by far, the most exciting presentation that we've given to-date in HighPeak.
We are pleased to announce and update our shareholders on the progress of the company and provide additional details on our recently announced Hannathon properties, as well as other acquisitions that we have consolidated over the last quarter.
We are substantially a different company today compared to a year ago and this will be obvious from the information we're going to discuss throughout the presentation. We're going to try to spend as much time as we can in updating you on current prices, production rates.
We're approaching cash flow neutrality and expect to transition to positive free cash flow in the second half of this year [ph]. And this is all while maintaining our trajectory on production and current growth.
If prices continue at these levels during 2023, we expect to be one of the few, if not the only US company which is substantially increasing production and generating significant free cash flow. As I've stated before, HighPeak is definitely a differentiated growth story.
If you'll turn to slide four in the presentation, there's many interesting things. And I want to refer everybody [ph] to the press release recently, because our stock’s down right now quite a bit. And this is a super buying opportunity. And in fact, when you look at the press release, it's easy to say, well, if our production went from 15,000 barrels in the first quarter to 12,000 barrels and now HighPeak legacy is at 25,000 barrels with Hannathon we're over 28,000 barrels -- 30,000 barrels a day.
Well, you might say, what about missing your first quarter production? We've added almost three additional drilling rigs. We've added multiple frac crews, we are approaching the guidance that we said that we were going to maintain throughout the year. We're actually ahead of our guidance in terms of where our production is today. And we have almost 30 wells that are still in progress being completed and coming online. We have an unhedged cash operating margin of $71.71 and which is the highest in the industry, our profit margin.
Another thing that people don't realize is what is the operational and Midland group accomplished in addition to production relative to our overall viewpoint. And that is we've gone from 63,000 acres to 91,000 acres, and we've done -- that's almost a 45% increase in four months in acreage position, increasing our scale and keep -- increasing our exposure -- and as we go through the presentation, you're going to see a lot more interesting things conceptually with an increase in acreage.
We also announced the Hannathon acquisition, which is a large acquisition of $255 million in cash and 3.78 million shares of HighPeak. This gave us along with the -- what we call the Alamo [ph] acquisition to the North almost 150 net locations at a three times EBITDA multiple, very, very accretive transaction also increasing our flow and increasing our leverage in terms of liquidity for the shareholders. So -- and it had a $70 million plus economic value in terms of present value synergies in that acquisition.
If you'll now turn to Slide 5, this is probably the most important slide in the entire presentation. It shows you our history from when we went public of 50 -- some barrels a day going up in the second part of that and then going back down again. And that's that going back down again is very similar to what happened in the last quarter. Then up to almost 15,000 barrels a day, then down to 12,100 barrels. It begs the question, why does the production go up and why does it go down?
There's not anything wrong fundamentally with the reservoir. There's not anything fundamentally wrong with anything we're doing. When you add that many rigs and reemphasizing again frac crews, and you can look down at the bottom of the page and see when do you get contribution from these rigs? Because initially, you actually get negative contribution you're in a block situation where you can't frac. You have -- we literally shut in almost 12 wells at different points in time during that quarter to go up to the next level.
Now on a pro forma basis, if you look at the star and see where our production is going straight up in the first star you see pro forma with Hannathon, our projection without Hannathon is still higher than what we projected. But our production with Hannathon is actually even higher. And we have increased our guidance from 32,000 to 37,000 barrels a day for the year as an average. And then when we go to our exit this year between 47,000 and 53,000 barrels a day. And we don't even start getting impact from our fourth, fifth and sixth rig now with Hannathon until later in the year. And then at the end of the year, we're going to exit at an average of almost 67,000 barrels a day, if you take the midpoint of that.
I'm going to spend more time talking about that throughout the presentation. But this slide shows you this was not anomalous. It isn't like we put on a lot of locations and pad sites that are coming on temporarily and come down. This is just part of our growth profile and we are hitting our numbers. Personally, I'm so excited about what's taking place. When you think about doubling your production in 4.5 months, and showing that same growth profile through the rest of the year, it's phenomenal for our company.
Now going to Slide 6, this also gives you a sense of our oil weighted growth profile, and it's going to continue as we go on. We mentioned about going into an average of 67,000 barrels a day at the end of 2023. This is in keeping with our plan to run the six rigs, but going beyond that and looking at exit production of almost 80,000 barrels a day in 2023. These aren't hypothetical numbers. We are hitting these numbers as we drill, and we're having the success that we had planned on. We have had to increase our capital budget. Our exit rate is already accretive when we go forward from where we are right now today with oil prices where they are, we are not out spending anymore as we go forward and count for roughly 30 wells that are in progress that will be pretty continuous now for the rest of the time.
So on an average basis, almost $1.2 billion a year in exit. And at the end of 2023, we expected to be above $2 billion, which gives us tremendous free cash flow and opportunity. And that's still just maintaining six rigs as we go forward, which gives us almost 150 to 175 new locations with the excess, very, very successful, very, very repetitive, and we are in process drilling now.
If you look on Page 7, which is adding cash flow, scale and development opportunity, the first part of that on the left-hand side of the page is Flat Top. It shows our bolt-on acquisitions, which we divide into basically three now. Our area we call to the north is north of the black line and that's kind of a circle showing what we're doing in that area.
And a lot of it is because this is well performance. And we're going to talk more about that, but all that acreage to the north up there in Borden County, that's the county line. It's the dark black line, almost in the middle of the page. We've added over 10,000 net acres there. And continuing to bolt-on and put together lump areas where we have 15,000 foot opportunities to drill these wells.
You're going to be extremely excited when Mike talked about the operational excellence and what's happening to those wells. But that's adding to our area. We added infrastructure to the area. I'm not going to talk much about that at this stage in this, but moving from 63,000 to 91,000 acres as you go into the Hannathon area.
It's almost the whole western part of that area now that we control 100% of adding 18,600 acres to that particular acquisition, buying it at a three times multiple on where present production is and being able to almost double that production in a period of between now and year end from 3,700 barrels up to 7,500 barrels a day. So again, we're extremely excited about it.
And I think you have to look, none of us are selling shares. I'm one of the largest shareholders and I'm looking to try to acquire more shares, not sell shares because the company is so undervalued relative to what we have going on.
And I guess the best thing I can say the next thing to talk about is our operating margins, and I'm going to turn that over to Mike Hollis, who's going to give you insights on operations, insights on profitability and why we are still the peer-leading best in the business. Mike?
You bet. Thanks, Jack. You know, if you now to slide 8. Q1 2022 margins. Everybody has heard me say this before, not all BOEs are created equal. We've got a much different commodity mix than most of our peers in the Midland Basin. The slide 8 highlights HighPeak’s continued unhedged peer-leading margins.
Our Q1 margins were 21% above our closest peer and 33% higher than the peer average. We are also positioned for further margin expansion with our LOE reduction initiatives and the dilution of fixed cost as our production continues to increase.
Our adjusted pro forma EBITDA margin of $73 per BOE based on our Q1 actual margin plus estimated uplift from near-term power projects and G&A per BOE reduction is 39% higher compared to our Q1 2022 year average. Further on average peer equivalent margin basis, HighPeak’s current pro forma production is equivalent to 39,000 BOE per day. I’d say in another way, it would take the peers production of 39,000 BOEs per day to equal HighPeak’s profit at our current pro forma production rate of over 28,000 BOE per day.
Turning now to slide 9, Flat Top Activity. We faced turns in the past about our acreage potential as we move to the east and Flat Top. All of our modeling had suggested that it would be similar across our entire block. But I'm pleased to share some well results as we now have oil in the stock tank.
As shown in the red outline on the east of the map, we have several wells that have IP-ed above 1,000 barrels of oil per day, and some that have reached up to 1,200 barrels of oil per day plus associated gas.
Similarly, on the far north side of the flat top, we again have wells that had demonstrated peak oil rates of over 1,000 barrels of oil per day with some reaching 1,300 barrels of oil per day. These results speak to validate our newly acquired acreage in this area.
To the far southern side of our acreage, an offset operator has recently drilled a new Wolfcamp D well as in Delta with an exciting initial rate of 950 barrels of oil per day. It is safe to assume that HighPeak will be testing the Wolfcamp D in this area. We are in full manufacturing mode in flat top and plan to run an average of four rigs and two frac crews for the remainder of the year.
On the operational front, I'm excited to say, our flat top substation has recently been commissioned and that we are in the process of switching our wells over to highline power. This will result in the removal of over 50 rental generators, across the field and significantly reduce our LOE. We are estimating that by the end of the second quarter, we'll have removed roughly 39 of those 50-plus generators.
The substation will also give us the ability to power our drilling rigs on electrical power, which factoring in today's diesel prices could provide savings of over $100,000 a well. Our 13-megawatt solar farm project is still on track to be completed in the third quarter. And I hope to be able to tell you later this year that, we are actually drilling with Sunshine.
Our contracted local sand mine project is estimated to be operational in June, and is projected to provide savings of up to $300,000 per well, when factoring in current sand cost and reduced round trip trucking cost.
Our flat top water infrastructure system, which includes recycling produced fluids and local non-potable water sources is currently servicing 100% of stimulation fluid needs for our 2 frac crews in flat top.
I'm also excited to report the initial section of our crude oil infield gathering system is operational, and the remainder of the system is nearing completion and is expected to be fully tied in by the third quarter.
Also HighPeak's, low-pressure natural gas gathering system is operational. And all of these initiatives enhance HighPeak's, operational and capital efficiency. Again, we are in manufacturing mode.
Turning now to slide 10. Signal Peak activity, the success of our recent well results in Signal Peak are confirming, all of our geological modeling interpretation for this area. Using 3D seismic, petrophysical models, cuttings analysis, geochem, sidewall cores, whole cores. We knew this area was going to be commercial. But like I stated before, now we have oil in the stock tank.
We couldn't be more excited about this area and its increasing importance to our growth trajectory moving forward. The fantastic well results from our delineation process in this region, which includes wells in the Lower Spraberry, Wolfcamp A, and Wolfcamp Ds and Delta are all meeting or exceeding our expectations.
Looking at the map designations, bullet number one highlights the location of our 10,000-foot Martin Wolfcamp A and Lower Spraberry wells. These wells were turned online in February and March, respectively and are continuing to increase production with current rates of 1,000 barrels of oil per day and 800 barrels of oil per day, respectively. These wells are located in the center of our block and prove up formations across a wide area spanning from the far western side of our newly acquired acreage to the center of our legacy Signal Peak block.
Bullet number two shows the location of our 15,000-foot Partee and Powell laterals in the Wolfcamp B. These wells were turned online in early April and are currently producing 800 and 900 barrels of oil a day, respectively, with significant associated gas. This two-well pad represents a successful test of 30,000 lateral feet of the Wolfcamp D reservoir across the center of our legacy acreage position.
Bullet number three, provides a location of our 10,000-foot Powell Wolfcamp B well on the very eastern side of our acreage block. This well was recently turned online and is currently producing 500 barrels of oil [Technical Difficulty] continuing to ramp up. This successful test well delineates and validates the productivity of the Wolfcamp D reservoir across our entire block.
Bullet four shows the location of our second two-well 15,000-foot Wolfcamp D and these wells have been drilled and are being completed as we speak, and we should have them online in June. I'm also excited to announce that we are already utilizing recycled fluids on our current frac job in Signal Peak.
Bullet five shows the location of a four-well 12,500-foot Wolfcamp D pad that is currently being drilled on the Hannathon block. These wells are scheduled to commence completion in July and should be online by the end of the third quarter. In conjunction with our updated guidance, we plan to average one rig on legacy high peak acreage and continue Hannathon's current one-rig drilling program on the acquired acreage for the remainder of 2022.
Turning now to slide 11. I I'll spend a few minutes discussing the infrastructure picture at Signal Peak. As you can see on the map, we will be inheriting a comprehensive produced fluid system with our Hannathon acquisition, which includes three existing SWDs and infield gathering pipelines covering the full extent of their acreage position. During the remainder of 2022, we will continue to build out the water system on the legacy high-peak acreage to provide for increased recycling capabilities.
And as you can see on the map, again, it will be almost effortless to integrate the high peak build-out into Hannathon’s legacy system back to the West. We are currently in discussions with multiple oil gatherers to build out a gathering system across the acreage, and we plan to be in manufacturing mode very soon in Signal Peak as well.
Now turning to slide 12, Signal Peak Wolfcamp D Economics. We get asked a lot about the Wolfcamp B again as in Delta and if it will compete for capital. The answer is, absolutely, it will.
Slide 12 details our single well, Signal Peak Wolfcamp D economics, based on type curves from Cawley, Gillespie from our year-end 2021 reserve report for 15,000-foot laterals. These wells achieved pay out quickly and provide high net present value. They deliver tremendous rates of return with today's commodity prices, but are still very economic at lower prices. They provide high recycle ratios as high as 6.2 times and $100 oil. The Signal Peak Wolfcamp D breaks even at a very low oil price, $34 a barrel. The graph also shows payout sensitivities compared with capital cost and oil price.
If you turn now to slide 13. ESG at HighPeak. Our ESG initiatives are both environmentally and fiscally rewarding to all of our stakeholders. As evidenced throughout this entire investor presentation, ESG is inherent in everything we do. The initiatives we put in place for our cost cutting and efficiency efforts are not only fiscally rewarding, but are also the right thing to do from an environmental and social perspective.
We utilized recycled fluids for over 70% of our stimulation fluid needs in the first quarter in Flat Top, and are currently providing 100% of our stimulation fluids in Flat Top from our recycling system and non-potable water systems. Our HighPeak substation will not only save us money on the OpEx and CapEx side of the equation, but will result in the removal of rental generators and allow us to power our rigs with electricity and solar power, which will result in the reduction of carbon emissions and fuel consumption.
Utilizing the local wet-sand mine would not only cut down on sand cost, but will result in a material reduction of total truck miles and the associated natural gas combustion that's needed in standard dry sand operations. Our new gathering systems not only increase our realized prices that we receive from our products, but will also reduce trucking and emissions. Our Flat Top crude oil gathering system, once it's fully operational will result in the removal of 160 trucks per day from local roads. And I'm extremely proud to say that we still have had zero employee safety incidents to date.
Turning now to slide 14, mitigating capital cost escalations. Again, inflationary pressures are real. It's what are you doing about it? So this slide details how management is constantly looking ahead to combat rising inflationary and supply chain pressures. We saw these pressures coming in advance and took serious preemptive steps to protect against cost increases. We're attacking cost savings from all sides of the equation. For instance, again, our wet-sand mine project on the capital side has the potential of saving $300,000 per well and again, reduces the cost for trucking, reducing a round trip from 150 miles, round-trip to less than 10, pre-purchasing equipment, such as tubular goods, tanks, vessels and ESPs.
Again, HighPeak substation will allow us to run our Flat Top rigs off of electricity and solar power, which will save on diesel cost. As we mentioned before, our water system provides increased recycling capabilities in both Flat Top and Signal Peak.
The main takeaway from this slide is that due to the preemptive measures that HighPeak put in place, we expect to stay within our guided CapEx budget, despite the serious inflationary and supply chain cost pressures that are affecting our entire industry.
And with that, I'll turn the call back over to Jack.
Thanks Mike. Everybody turn to slide 15. It will give you a sense, again, in terms of what we talked about. I want to emphasize our 2022 guidance that we're right on track for, our 2023 guidance to we're right on track for, showing us to exit at an average midpoint of 80,000 barrels a day.
Think about going basically from 12,000 barrels a day at the end of the first quarter to end of next year at 80,000 barrels a day, still maintaining the capital expenditure budget, because of the preplanning that we did that so many companies didn't see coming, having total cash costs of very low finding and development cost and being able to divide our activities between two great areas that are showing complete performance success that we're tremendously excited about, and doing it with realized pricing that is among the highest in the industry.
So, when you look at that and you see that growth, and that's what I want everybody to focus on is looking at our growth.
And now turning to slide 16. There is no question that our growth story is going to continue on, and it's a responsible story. We are now approaching complete, not any overspend, but complete success within our own budget. We have definitely operational excellence, thanks to Mike and his team.
We have a strong balance sheet, even post closing this. In terms of borrowing money and utilizing our reserve borrowing base, we are going to be in great shape from a debt to equity. We've always said, we're going to maintain one year debt to equity.
Our goal is to maintain our peer-leading margins also. And actually, with the implementation of the things that Mike talked about, our margins are actually going up, instead of going down, like most companies are.
We believe in basically under-promise and over-perform. We are not running our company quarter-to-quarter, which you could look at and say, well, maybe we didn't hit our numbers. Well, those weren't our numbers. Our guidance is based on a yearly guidance basis, and not quarter-to-quarter.
Our goal is to making money and making sure that we do things responsibly and take the necessary time to put our wells on to produce our wells properly to maximize the profit for everybody.
Right now, we're running our company on the basis of all 10 fingers. That includes a great proactive drilling program as well as the three acquisitions we made, making sure that when we do consolidation opportunities, we do it on an accretive basis to make the shareholders' money. We're going to continue doing that. And we -- this is truly the best quarter that we've ever had relative to where we are today versus where we were at the end of the year and that is going to continue forward. So, we're excited about it and now open up the presentation to any questions that anybody might have.
Certainly. [Operator Instructions] Our first question comes from the line of John White from ROTH Capital. Your question please.
Good morning guys and I -- Jack, I appreciate you spending a lot of time on my guidance and where production is -- the wells being knocked off line by offset fracs. It doesn't concern me. People that follow the industry know that happens to everybody from time-to-time. I'm glad to see slide four has been updated to include the new acreage to the north of flat top and you're not going to tie hold me like you did on the last call. So, you've expanded flat top mainly to the north and you've expanded Signal Peak mainly with the Hannathon mainly to the South and the West. Is that correct?
Yes, that's correct.
And then on slide nine at flat top, the circles are indicating activity going forward is going to be focused on the northwest part of the block and on the southeast part of the block. Is that correct?
Yes. We'll have other activity all the way across the block in terms of drilling and development, but we were just showing that since it was new to the northwest -- and since there have been questions regarding moving east to the south, we wanted to demonstrate what the success has been in our northern area in terms of why we made that acquisition and the results of the wells that are being drilled there and then moving down to the Southeast to show that we now have wells in the 1,000 and 1,200 barrel a day range and even two more zones down there that are coming in. So, it's just showing that the entire acreage block is now perspective and we will be in process mode to start developing the whole block.
Okay. Thanks for that clarification and I'll pass it along and get back in the queue.
Thanks John.
Thank you. Our next question comes from the line of Nicholas Pope from Seaport Research. Your question please.
Good morning everyone.
Good morning.
Hey, I was hoping you guys could talk a little bit on Signal Peak. You got a bunch of new data here. It looks like the Wolfcamp D, I mean, kind of confirming what you all thought about being fairly extensive across that acreage position. I guess what did you learn with the new the Wolfcamp A and the Lower Spraberry in the Signal Peak and kind of like how extensive you think the potential could be on the asset, or has it changed, or is it kind of just kind of confirming what you all have been thinking about that -- those different formations?
You bet, Nick. No, you're exactly right. It confirmed our initial estimate that the Wolfcamp A and Lower Spraberry, we're going to be very productive and perspective on our Signal Peak acreage. Now obviously, we kind of step out, if you look at the Wolfcamp A, the closest Wolfcamp A production is over to the West of the Hannathon block.
So again, part of the strategy of drilling the Wolfcamp A here and 1,000 barrel a day production and associated gas that we have today helps prove up from the western side of Hannathon at least over to where we have 1,000 barrel a day well. And we expect it to move over into the middle part or more of our legacy Signal Peak block. So again, it was just more of a confirmatory delineation well.
The Lower Spraberry, there was a little bit of well control in the area a little closer. But again, met and exceeded our expectation. The Wolfcamp D, as you mentioned, it's its perspective all the way from the West to the East, North and to the South of our acreage block. So again, we're very excited about the runway of those three zones as well as Hannathon has done some delineation in the Wolfcamp B, as well. I don't know if you have anything else you want to add, Jack?
No. The only thing I would add, Nick, in addition is we do a lot of technical work that even the majors don't do. And we -- we've done a lot of additional petrophysical analysis, core analysis, sidewall cores all the way across and analyzing this area.
And we've talked about the hurdle of zones, so I'm not going to add too much there, but we think we understand it much better now, as a result of this drilling and further evaluation. And that we perhaps will have some really exciting things happening in that particular formation also as we go forward.
But undoubtedly, our goal was to delineate towards the all the way across, make sure it's commercial and add those roughly 500 -- 400 to 500 locations to our inventory. And you've seen the economics of it. So we're really excited about it.
Yeah. That's great. And as you kind of think about the hierarchy of like wells both comparing, what's the Flat Top and kind of what -- where we are at kind of in -- kind of delineating Signal Peak. I guess, has anything changed in terms of like where you think priorities are or like what the economics look like? And how do the economics, I guess, compare in Signal Peak with what you've seen Wolfcamp D versus kind of the Lower Spraberry and …
Yeah. You have the economics in the presentation on Wolf D and a great comparison is to go to the appendix, and in the appendix, you'll see the economics on the Wolf A and overall, which includes -- it's basically the same in the Flat Top area and in the Signal Peak area in terms of those economics.
They're so close. There's no doubt that it's a little bit better in the Wolf A, but they're both very competitive. Our breakeven cost is 29 on the Wolf A, it's 34 in the Wolf D, but our returns at $100 oil are in excess of 200% in both areas. So, it's very comparable. It's very good and anybody would put these in the top tier of their investment profile on any acreage, anybody has in the Delaware or in the Midland Basin.
Awesome. That's great. I appreciate the time, everyone.
Good. Thank you, Nick.
Thank you. Our next question comes from the line of Jeff Robertson from Water Tower Research. Your question, please.
Good morning. As you all look at flat top, you -- Mike or Jack, you have a lot of densely spaced wells on the western side of your block where you initially moved into development mode. As you move away from there and go out, either to the east or north into Alamo, were you -- is it fair to assume you will not have the same type of impact from having to curtail -- offset production as you bring new wells online?
Yes, Jeff, as you mentioned, we had to go in and infill some of our kind of delineation wells, kind of had some book and drilling that had production on either side. So, yes, the amount of wells that we had to shut in for protection, as well as some water out effect, was a little higher over the last couple of quarters than what you'll see going forward.
But also, when you go to manufacturing mode, you tend to drill more wells off of a pad. And, again, you're only going to be on one side of a set of wells. So the amount of disruption to that production will become smaller over time overall, as well as the growth profile that we have.
The base is getting large enough now, as well as the growth is accelerating. So to have couple of hundred barrels a day per well off for four or five wells on and off throughout a quarter, will become less and less apparent in the growth profile as we go forward.
Just know, every company everywhere in the basin turns wells off and sees water-out effect. It's just how big of an effect do you see in the daily production, it will become less and less of a percentage for us going forward.
And, Mike, have those wells generally come back -- as you've returned wells to production, have they generally returned to their type curve profile?
Absolutely, between shutting wells in for fracking, shutting wells in for weather events, COVID, a number of events that happen, these wells get turned on and -- or turned off and return to production many times through their lifetime.
We've got wells almost 3.5 years old that have went through those cycles, have had wells fracked on either side of them at different times. And through every one of those events, just like they do in the center part of the basin, and the rest of the Permian in general, the wells come back on. You get a little flush production, and then they come right back on to their type curve.
A question on Signal Peak, I think when you all announced the Hannathon deal, you referenced that they had a 3D survey. I think you all have a 3D survey of your side of the acreage. Can you merge those two surveys together and maybe use them to high-grade landing zones within the Wolfcamp D
Absolutely. So, of course, once we close the transaction, we'll be able to integrate the 3D seismic that Hannathon has and be able to utilize it in the same kind of 3D earth modeling and trajectory pathways that we're utilizing now in all of our legacy assets.
If I remember right, the Wolfcamp D is a pretty thick formation in Signal peak. Is that -- am I remembering that correctly?
You are remembering that correctly. Yes, sir. It's pretty thick, roughly 450-foot thick. So again, a lot of resource in place.
Are you testing different landing zones?
We've got a -- we've kind of got our preferred landing zone as we sit today. And again, just being pragmatic kind of scientist we -- and engineers, we like to -- we like to do what works. Now does that leave some room in the future for Chevron into the different landing zones within the Wolfcamp D, it does, but our preferred development plan right now is to stick with what we know performs and produces these kind of results.
And last…
One thing I would add, Nick, to that and what Mike is talking about, when you look at this area from a macro perspective, and I've been doing this now for 52 years. And one thing Mike says is oil in the stock take. This area now, from a process perspective, looks to have recoverable oil from these zones, these big zones, the oil in place and the ability to recover this could be approaching now a net to high peak of $1.5 billion barrels plus of oil. It's a tremendous reservoir, tremendous opportunity and like every reservoir, in fact, our team managed over 27% of the tertiary recovery floods in the Lower 48, which are the biggest oil fields in the Lower 48 in the United States. And in every case, over time, we will improve the recoveries. And we don't expect that to be different here we're getting better and better of picking the landing zone and figuring out how to complete the wells and how to maximize the recovery. So the fact that we have such a tremendous amount of oil in place it's going to get better and better as time goes on.
Thanks, Jack. One last question on infrastructure. You highlighted the water disposal system that Hannathon has and that you all have existing on your legacy Signal Peak acreage. Mike, can you talk about how you can leverage this bigger acreage block into cost saving measures, whether it's discussions with crew gatherers or as you start to think about a manufacturing mode here? And are there power solutions that you can provide across a bigger acreage that will deliver on the operational cost synergies you all cited when you announced the deal?
You bet. If you look at what we did up in Flat Top and how we've integrated everything together, which again, works on that efficiency equation from cost on OpEx, CapEx as well as realized price. Having a big consolidated block like we now have in our Signal Peak area once pro forma Hannathon, it definitely gives you a better ability to work with partners on the gathering side. the existing water infrastructure that Hannathon has. We are currently connecting with Hannathon and sending water to some of their SWDs. So again, there's some synergies day one, they will be able to accelerate. Having more production from the wells that we have across this entire block allows us to have a higher recycle percentage from stimulation fluid, both from an ESG standpoint as well as from a cost savings standpoint. So all in all, whether it's oil, gas, water, power, having a big consolidated block absolutely helps. It's one corridor across all of it that allows you to efficiently develop your wells and produce your product.
Great. Thank you very much.
Thank you. Our next question comes from the line of John White from ROTH Capital. Your question please.
Yeah. Thanks again. On Slide 10 and referencing the previous discussion, I think, Jack, you mentioned that you think the economics for the Wolfcamp A and the Wolfcamp B are going to be neck and neck?
Absolutely.
That sounds good. Congratulations on getting that Powell well out there to the Far East, that's a real nice control point for your Wolfcamp B on Signal Peak. And Mike, congratulations on getting your substation commissioned. Jack, you mentioned the formation you called it Hutto. Is there a more conventional name for that?
Well, it's a part of the Wolfcamp C zone. It's a specific zone in that. And the reason it's called Hutto is there is a vertical field in the northwest part of our block that produced approximately 15 million barrels out of that zone. And so we're just moving across, just like we did on the Wolfcamp D, it wasn't like we moved out and drilled a wildcat well, we had a tremendous amount of well control. We had a lot of data. We had samples in the area. We had core analysis, the same with the Hutto. There's enough vertical production in the area we pretty well know what that zone is going to -- how much oil is in place and is simply getting in the right location and landing the well properly to get the oil of the ground.
Again, some real nice control points there, and thanks for that. Mike, did you mention dry sand and wet sand?
Yes.
What's…
Well, it's typically the sand that we use in our completion operations is dry. It would look like sand from a sand dune, but typically, how you recover that as it's mined from the surface mine and then it's cleaned and it's wet and then they typically have to use natural gas burners to drive the sand, which makes it easier to transport and to all float at the frac job.
Utilizing wet sand, you take a step out of that and a lot of BTUs have to be burned and utilized to drive that sand. And the industry has gotten -- the technology has gotten a lot better lately to where wet sand utilization no longer causes the usual headaches of having kind of clumpy wet sand. They've got all that figured out and are able to off-loaded for the frac jobs very efficiently. So that's really the difference.
Okay. I appreciate that explanation. And I'll pass it on.
Hey, thank you.
Thank you. Our next question comes from the line of Mark [ph] from Wexford [ph]. Your question, please.
Hi. Thanks everyone. Can you talk about the timing of the bank redetermination, give us a general idea of what you expect the amount of the line to be how much cash you think you'll have in excess what you have to draw in order to pay for Hannathon?
Yes. That's a good question. We are working that process. We're about midway through working with the banks and looking at all alternatives, because we want to get the cheapest financing possible and the best financing possible. So we don't have an idea yet as to what the amount will be. We know it will be in excess of the $200 million and it will be enough to go ahead and close the Hannathon transaction. We already have commitments for that. But -- in combination with that, we're looking at all the alternatives available in the marketplace right now. And we should have that outline probably within the next 15 to 20 days. And know exactly the direction we're going to go.
That's helpful. I guess it kind of does make me wonder when you say cheapest and best. I mean, is there something other than a bank line that you're considering?
We're always looking for the best alternative from bonds, convertible bonds. We did an equity -- I mean, a debt offering earlier this year that was a very attractive financing. The RBL is a very attractive financing, but it does have a lot of restrictions on it in terms of hedging.
We're very bullish right now on what oil prices are going to do over the course of the next 12 to 18 months. And so we're just going to cautiously go into this. And make sure that our – that is absolutely secure and that we have the best financing available for the strategy that we have going forward.
Okay. Thanks. Then could you just switching gears, could you put a number on the number of barrels that you feel were curtailed during the quarter?
Yes. Off and on, I would say, at one-time, we had 12 wells offline. But on an average, it would probably be in the neighborhood of 5,000 to 6,000 barrels a day or curtailed during the quarter.
No, that's helpful because that's probably more than I thought, and I suspect maybe others may be as well. So thank you. Okay. Thanks very much.
Thank you.
Thank you. This does conclude the question-and-answer session of today's program. I'd like to hand the program back to Jack Hightower, Chief Executive Officer, for any further remarks.
Well, I've been doing this for a long time, 50-something years of multiple public companies and executive committee and consulting for public companies. And honestly, this is one of the most exciting periods of time that I've had to report on. It's disappointing that our stock has gone down and I think it's the nature of algorithms and people looking at it and have their internal thoughts on where our production should be -- but when you're new and young in the equation to accomplish what we've accomplished going forward and getting our production where it is.
It's a tremendous accomplishment. We are very excited about what's going on with the company, with the delineation of our production and reserves and consolidation. We're going to continue this activity and you're going to see 800-plus thousand barrels a day exit in 2023. So hopefully, you'll understand, my job is to make sure everybody makes money and that's what we're going to be doing for you. Thank you very much.
Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.