Highpeak Energy Inc (HPK) 2021 Q3 法說會逐字稿

Good day, and thank you for standing by. Welcome to the HighPeak Energy 2021 third-quarter earnings call. At this time, all participants are in a listen-only mode. (Operator Instructions) I would now like to hand the conference over to your first speaker today, Steven Tholen, Chief Financial Officer. You may begin, sir.

Good morning, everyone, and welcome to HighPeak Energy's third-quarter 2021 conference call. Representing HighPeak today are Chairman and CEO, Jack Hightower; President, Michael Hollis; and Vice President of Business Development, Ryan Hightower; and I am Steven Tholen, the Chief Financial Officer. During today's call, we will make reference to our November investor presentation and our third-quarter 2021 earnings release, which can be found on HighPeak's website.

Today's call participants may make certain forward-looking statements relating to the company's financial condition, results of operations, expectations, plans, goals, assumptions, and future performance. So please refer to the cautionary information regarding forward-looking statements and related risks in the company's SEC filings, including the fact that actual results may differ materially from our expectations due to a variety of reasons, many of which are beyond our control.

We will also refer to certain non-GAAP financial measures on today's call. So please see the reconciliations in the earnings release, which was issued on Monday afternoon. Our prepared remarks will begin on slide 4 of our November 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 want to welcome everybody to our third-quarter conference call and basically, [animate] this is a very exciting report we have for you. We know that you have your press release and can look at financial numbers. And as we have mentioned earlier, we have lumpy production. So therefore, our financials are not as exciting.

But when you look at our production, this is a significant growth story for 2022. We added our second rig early into third quarter. We're focused on drilling large in-fill pad in our Flat Top operating area. And as we mentioned in our August call, we expected that this would cause our production volumes in the third quarter to be lumpy because we had to temporarily curtail some of our producing wells, and I'll go into that in more detail throughout the presentation.

But now that's behind us, our production volumes and getting our wells back online and getting new wells starting to produce; we've rebounded nicely. And since the beginning of October, we've been averaging approximately 15,500 barrels of oil a day, which is almost an 80% increase over and above our production in the third quarter.

And that is a tremendous increase in production. It shows you the benefit of having our oil production go back, come back online successfully and then how much success we're having in adding our new wells. So it's important to note that these production levels are a product of our initial one-rig development program. So wells that are drilled with our second rig will begin to contribute meaningful production volumes in early '22.

And then we're going to, in addition, due to our excellent well economics and current strength of the commodity market, we've added a third rig in late October and now plan to add the four years in, another rig -- the fourth rig. We will continue to pull our present value forward for our investors, and yet we'll do all this while maintaining our philosophy of staying less than one time debt to EBITDA. So we have we'll go through the financials and talk about that as we go forward.

Now if you'll turn to slide 4 on your presentation. And it's really interesting I think to look at Howard County is the faded white line and all the activity in Howard County, but when you see our acreage block -- our two contiguous acreage blocks and what we've added the Signal Peak from the last conference call and what we have up in Flat Top now, it's a tremendous acreage position. In the quarter, we averaged 8,200 barrels a day compared to 8,900 barrels a day in the first quarter. And we, of course, told everybody that our production would be [off].

We literally had between 4,000 and 6,000 barrels a day, shut in during this period to frac other wells. And but since mid-October, we've averaged 15,500 barrels a day. We've increased our acreage position up to 62,000 acres, and we still operate 92% of our acreage position. We significantly close 10,600 additional acres during the quarter. This gave us almost 100 more additional locations.

So when you look at us as a whole and even with four rigs drilling, we're going to have plenty of inventory, plenty of growth forward value, and our production increases that we'll talk about later. We're going to continue increasing throughout 2023 and beyond. We also have still the highest cash operating margins of any of our peers of $51.88 and an average realized price of $63.18 through the quarter.

On page 5, the next slide, to me is the most exciting slide -- one of the most that we have at least through this quarter. And it gives you an explanation of when we started getting the [33,300] barrels a day. And then we had the COVID-19 that was during that period. Then in a short period of time, we had the Winter Storm Uri that took our production off. We increased from that up to 5,300 barrels a day in the first quarter.

Then we started back with our program and our production started taking off. And of course, then we had the offset fracking where we had to shut in each of those categories that've inhibited our growth during the period. And then all of a sudden, we get our wells back online and look at our production taking off in the third quarter or beyond the third quarter into the fourth quarter and throughout the end of the year, just going straight up. And that's significant -- and that's what one (inaudible), and that's significant because we're growing our production expedientially. We're adding the second, the third, and the fourth rig before year end. And that growth is going to continue on into 2022.

Turning the next page, getting to slide number 6. We continue to receive great prices for production. Our realized price of $63.18 is 89% of [WT Oil is]; higher than any of our peers in the industry. And even with our hedges in place, and I'll point out we have a lot -- and later on, I'll point out we have a lot of hedges that are -- very small amount of our production is hedged and we have plenty of exposure to price increases with oil prices going up.

Our CapEx in the third quarter was $64 million, excluding acquisitions. We drilled over 124,400 feet of lateral foot, not including our second horizontal SWD wells. So we now have two horizontal SWD wells. We think we've only two in the United States, and they are very sufficiently handling our water disposal meet up in Flat Top. As mentioned in our call, this quarter is really the stepping stone for growth as we go forward.

Now if you turn to slide 6, and looking at that, we mentioned that in our press release, the earnings were down from $40 million to $33 million, principally because of having our wells offline. Our CapEx, we mentioned what we were doing there. Our realized pricing is still fantastic compared to our peers. Our production is starting to come back up again. And so I wouldn't pay too much attention to this, in the sense of we knew this was going to happen. We knew we had to take these wells offline.

When you take wells offline, your LOE goes up, your G&A cost per barrel goes up. All of these things will go right back into very efficient and being number one in our class as we exit the year and this quarter.

Now I'm going to turn it over to Mike Hollis to discuss the operations and the margins in some of the next few slides. Mike.

Thanks, Jack. I'd like to start by congratulating our team on maintaining our peer-leading cost levels in spite of recent industry-wide inflationary pressures. This is a statement to their cost focus attention to detail, and the measures they have implemented to keep our costs stable in this current environment. We've made great progress on our key objectives of operating and capital efficiency and have maintained our impeccable safety record while rapidly increasing our production.

If you turn now to slide 7, our 2021 margins driven by our low cost, high oil cuts continue to be peer leading, both on a hedged and unhedged basis. As shown by the benchmarking graph, comparing HighPeak to our Permian peer group, these margins will continue to grow differentially to our peer group in 2022 as we drive down LOE and G&A costs.

On the chart on the right of the slide, our LOE ran in third quarter -- ran a little high. This is a transitory situation. We foresaw this and began the necessary corrective steps last year. The bulk of that transitory operating costs were related to three factors. First, our overall lower production in the third quarter due to curtailing material production for all set completion operations. We had roughly 10% less BOEs to spread the cost over.

Second, cost incurred as several new wells are turned online but prior to their production ramp-up. And lastly, our current rental generator usage until our new HighPeak substation is commissioned in the second quarter of 2022; this substation project remains on schedule despite the current worldwide supply chain bottlenecks.

Generator rental and fuel cost make up roughly $2.50 per BOE of this quarter's transitory change. But even this change will trend down towards the second quarter of 2022 as production continues to ramp until it goes completely away in May when we energize our system. This field-wide electrification project will substantially reduce our operating cost in 2022 and beyond but will also dramatically advance our ESG objectives.

If you turn to slide 8, in Flat Top, the map on the left-hand side of the slide. As you can see, our third-quarter activity was focused on multi-well pad development on infield locations, which was a driver to our curtailed volumes in the third quarter.

We have transitioned into full manufacturing mode in Flat Top, where we will focus 100% on multi-well pad development going forward. We have successfully delineated both the Wolfcamp A and the Lower Spraberry across our entire acreage position, as evidenced by our very robust well results in both of our key formations on all sides of our block and look for HighPeak to methodically develop other benches in 2022.

In Signal Peak, the map on the right-hand side of the slide, in the fourth quarter, we will utilize our third rig to begin initial pad development across our acreage block. We are currently drilling in Wolfcamp A and Lower Spraberry pad, and we'll continue the delineation of the Wolfcamp D formation based on the strong well results from our successful Wolfcamp B well, as well as the excellent results from offset wells in the area.

We can't stress how excited we are with the additional acreage we added in the third quarter, as well as the well results to date and standing up a third rig in our Signal Peak area.

If you turn now to slide 9, our team continues to be laser-focused on cost saving initiatives as shown by our third-quarter results, which remain flat with our prior quarters in spite of recent inflationary pressures. We are striving to keep our cost flat, even as we accelerate our development plans by increasing rig count. We're in the process of implementing additional measures, which will offset inflationary pressures and will help lower cost further. Recycling a higher percentage of produced fluids; this is a benefit to capital cost as well as operational cost.

On our current pad that we're fracking today, we are averaging 60% recycle fluid in a pump many stages at 100% recycle. We've also averaged 60% of our entire stimulation fluid for the third quarter was recycled produced fluids. Our local sand mine project will be operational by the second quarter of 2022 and will reduce overall completion cost and advance our ESG initiatives by reducing emissions associated with trucking.

Our third-quarter activity was focused in Flat Top, where well economics continue to be fantastic. These economics are a product of great reservoir performance, low cost and capital efficiency of our longer wells, high oil cuts, and our differentiated realized pricing; these drive phenomenal results. A 12,500-foot Wolfcamp A well at $80 oil pays out in less than six months from first production and generate an NPV10 of $20 million a well. And the Lower Spraberry is no slouch coming in at $18 million of NPV per well. These economics are tier one in anyone's portfolio.

Turn now to slide 10. Our team is hyper engaged with keeping ESG initiatives, metrics, safety, and the continued build-out of the necessary infrastructure in the forefront of all of our daily decisions. We don't view ESG as something we need to implement. It's merely the result of doing the right things.

HighPeak again utilized significant recycled produce fluids in our third quarter. We recycled over 2 million barrels during this quarter, which equated to approximately 60% of our entire stimulation fluid needs. We were able to utilize again over 100 -- our several zones, were completed with 100% produced fluid in the third quarter. And our HighPeak substation project continues to remain on time with an expected online date in the second quarter of 2022. This will reduce the need for generators, greatly reducing costs and emissions, and give us the ability to run our rigs of high-line power in the second half of 2022.

We also signed an agreement for a 13-megawatt solar farm, again coming online in the second quarter of 2022. During the daylight hours, HighPeak, we'll be using solar power to drill and operate our wells. We've had zero recordable safety incidents and continue to provide our employees with flexible work environment in this post-COVID world. It is a testament to HighPeak experienced team and ingenuity that we've had the success that we've had to date as we continue to advance our ESG goals while rapidly growing our activity in production. With my comments now complete, I'll turn the call back over to Jack.

Thanks, Mike. I would like everybody to the turn to slide 11 in their presentation. This is probably the most exciting slide and tells the story of HighPeak in 2022. If you look on the left side and you look at the curve that we had at the end of the third quarter, the bar that goes straight up, and then we takeover starting at the beginning of 2022 in the first quarter and see the (inaudible). So you're almost straight up on your production with a four-rig outlook.

We try to be in effect to underpromise and overperform in our presentations and what our projections are for the year and what our outlook is. But [relative to] our outlook, we're averaging almost 28,000 to 29,000 barrels a day; next year, we plan to exit at between 36,000 and 42,000. We feel like that's a conservative estimate, but you can see in and with that kind of growth, with four rigs running, with approximately $650-million budget, that's been approved byour Board of Directors, we feel like we can exit the year with an EBITDA or an EBITDAX of almost $600 million plus a year -- that's tremendous growth.

We know the last three weeks or so or month has been great for our shareholders and affect a 50% gain from our $25 million we raised in our offering. But this is really the story, and everybody has to make their own decisions. But when you look at this, and you look at our reservoir, and you look at the performance we have, the capital efficiency we have, with the team that we have in place, and our total overall return on investment with our differentials on oil pricing -- if oil prices stayed the same, our company is going to grow tremendously with our four rigs next year.

The next slide 12 also combines with growing production volumes, but also growing our reserves because as we grow our production volumes, we also grow our reserves, our [products], our proved and developed locations. So we will be adding additional reserves as we drill these wells. And one thing I'd point out on this slide is some of our growth is because of price increases. But most of our growth is because of drilling our wells.

We've actually drilled now and operate almost 62 wells, but only 33 of those wells contribute to our increasing $300 million of PDP. And these are only PDP values here. We do have some PDNP in some of the numbers. But on our growth profile, it only includes our proved developed producing, and that's at $723 million a t the end of the third quarter. We have almost 14 additional wells that will be coming online in the fourth quarter to be added to that. And that takes us in excess of $850 million to a $1 billion in PDP reserves going forward into next year's business.

So by adding 100 wells, you can see how our production goes up, (inaudible) to superficially, in your mind say, that for every well, we get at least one (inaudible), sometimes two proved undeveloped locations. So the growth of the company in terms of proved reserves, in terms of income, in terms of production is going to be phenomenal next year.

Turning to slide 13. If you think about looking at that, this is our liquidity and our financial overview. We've increased our credit facility now up to $195 million. That gives us undrawn capacity of approximately $100 million, plenty of liquidity. We will have the ability throughout the year to increase our borrowing base with the banks, short of anything happening and towards in terms of oil prices that we can't foresee at the present time, we're very bullish on oil prices at the present time.

We completed our $25 million offering and our [S3] eligible amount have a shelf offering. We do not plan on doing that; we don't need that capital right now. But that is a potential, if we did need capital for an acquisition or something. And of course, we've talked about acquisitions in the past that we would be very select and make sure it was a very accretive transaction before we would do it. But this gives us an EBITDAX target of debt to EBITDA still staying below one time.

At the end of the quarter, we were 0.6. That's a little unfair because we had a lot of production off by bringing these wells back on, we're less than 0.3 in terms of debt to EBITDA. And going forward, even with the four-rig program, we do not plan on getting beyond one time debt to EBITDA and exiting the year at approximately 0.3 to 0.33 times debt to EBITDA -- very healthy balance sheet going forward.

Now on slide 14. And looking at that, you can look at the -- this is kind of our hedge position. Keep in mind that philosophically we hedge to protect our borrowing base. We hedge to protect our capital budget. We don't speculate on hedges. Right now, we have approximately 4,100 barrels a day, hedged at a price of $65.80 -- Mike mentioned and alluded to how that compares to our peers.

Many of the public companies are having huge write-offs now and their hedges were in good shape, that gives us less than 20% of our per debt projected volumes going forward in the next year that our hedge. So we have plenty of exposure to the commodity, but yet we're going to hedge as necessary to make sure that we do it for protection. It's like an insurance policy. That's our philosophy. And as mentioned, we don't speculate on hedges.

So on slide 15 to kind of wrap up our story. This quarter was a major leap forward and a stepping stone for our growth going into 2022. Now we've added our second and third rig. We will stand the fourth rig before year end. We've maintained our peer-leading cost structure in the face of inflationary pressures, and that's a true testament to Mike and our drilling and operations team.

It's pretty phenomenal with the cost going up like they are because of their technological advances, their knowledge of the business, they've been able to continue, and project forward the $505 a foot in terms of our cost. So our team is extremely focused on operational excellence, and I'll continue to be very proud of the lean team and all the hard work that they do to accomplish for me and for our shareholders and stakeholders. It's just phenomenal what they're doing right now.

I think we're the fastest growing company in the country. And I think we're going to continue that way. But we're not going to do it by giving out over our skis. We're going to do it in a responsible way. And we're going to continue our peer-leading margins. We're going to continue with staying less than one turn debt to EBITDA in terms of leverage, and we're going to continue with our cost levels. And hopefully we are very set in place an opportunity to take advantage of these commodity prices that we see going forward.

So if you have any questions at all now, I'd like to open it up for questions.

(Operator Instructions) [John White, ROTH Capital]

Hello, operator.

Hey, John, we can hear you.

Okay. Yeah. The operator cut out there for just a second. Thank you. I wanted to make sure I understand Mr. Hollis's comment on drilling at Signal Peak. You're currently drilling a Wolfcamp A well and a Lower Spraberry well, is that correct?

That is correct, yes.

Okay. And then you plan to drill a Wolfcamp D in the fourth quarter?

Yes, sir, in the fourth quarter. We're currently drilling the Wolfcamp A at Lower Spraberry pad. We'll move and drill a two-well Wolfcamp D pad about 2.5 miles east of where we're currently drilling, and those will be two 15,000-foot Wolfcamp D wells. We'll again move down to the southern portion of our block and drill again, another 2-well Wolfcamp D pad, both 15,000 feet wells.

Okay. And the last two well pad for the Wolfcamp D that you mentioned, is that going to be in the first quarter of 2022?

Yes, the drilling will roll into the first quarter. The completion of all of these wells will begin at the end of the fourth quarter, roll into the first. So you'll see production late first quarter from all of this activity.

Okay. Thanks very much. And your 2022 guidance is very impressive.

Thank you, John. We appreciate it.

I'll pass it on.

Nicolas Pope, Seaport Research.

Hey, good morning, guys. I was hoping you could talk a little bit more about the power projects and the generators you have coming online. I guess what does that -- as you kind of look at the financial model and the spend you guys have been seen on that side of things, where does that show up? Is that where the drop in LOE is coming from? And I guess how much of the power are you all going to be able to generate for, I guess, the rigs versus operations? Just trying to make sure I understand what all that's going to.

Mike, answer that question (inaudible)

You bet, Nick. That's a great question and look toward in the third quarter going into all the way up to May of 2022, in our Flat Top areas where we're putting in the substation in a solar farm and that project, all of it will be energized together in May of 2022. But between the third quarter of this year and end of second quarter next year, most of the new wells we're bringing on, we're having to generate that power locally. So we're doing in a note -- numerous different ways, local generation with just a propane power generator, other places we build what's called mini grids, trying to reduce that total cost.

In the third quarter, with our 8,200 BOE a day and averaged about $2.5 per BOE, that costs, again, as these wells come online, the total cost will stay the same as it is today for the generators in place. So for BOE, that will go down between now and next year on the -- into the second quarter. We will continue to have to add some generators. So as you look into 2022, w here you can kind of think about it is our LOE was really hot in the third quarter; fourth quarter this year going into first and second next year, you'll see it drop roughly a $1 a barrel, each one of those quarters until May of 2022. And when that happens, we flip everything at Flat Top to our power distribution system.

So not only the generators, for all of our pumps, transfer pumps, but also our rigs are going to be plugged directly into the powerlines so that will have a direct CapEx benefit for us, as well as getting a lot of this local power and local fuel being burned and emissions will all now be efficient power from the power grid, as well as from our solar farm during the daylight, we will be running our rigs and operating our wells off of that solar grid. And hopefully that gives you a little flavor.

(multiple speakers) One thing I would add to that is when we bring all that back online in May or so of 2022, we anticipate our costs to go from that $8.97, down to about $4.50 to $5.25 for our LOE costs. So significant savings, when we bring everything in place.

Got it. That's great. I had one other additional thing on just kind of the shape of the production profile. Do you all anticipate any significant offset production impacts like you saw in the third quarter as you kind of add these other rigs? Or is that more specific to the third quarter and we shouldn't see that volume I guess [impact] going forward (multiple speakers)

Any time, Nick, you are in effect fracking close in and doing large pads. You can have some impact in terms of having to shut and offset production while you're fracking. But we won't see the impact that we had in the third quarter probably ever again.

We are -- the way we're developing our areas and with our pad and with our water system and infrastructure in place, we're going to be able to eliminate and reduce any impact, while we go forward. And almost 25% of our area down south in the [world deep] formations specifically, is not near as impactful as it is in some of the other zones. So we don't see -- we see it happening every now and then, but not like it was in the third quarter.

I got it. That's great. That's all I had. I appreciate the time, guys. Thank you.

Thank you, [ Dave].

Jeff Robertson, Water Tower Research.

Thank you. Mike, a s you all further develop the Signal Peak area, do you see the opportunity or necessity down there to do some of the same type of things that you've done at Flat Top, things like electric substation upgrades or enhancing accrued delivery contractor or solar -- any of those opportunities to enhance your cost in that area?

Thanks, Jeff. Yeah, that's a great question. And when you look at our CapEx budget for 2022, kind of the high-level way to look at that as about 75% of the CapEx go into Flat Top, about 25% of the drilling CapEx go into Signal Peak. However, when you look at the infrastructure that we've laid out, it's opposite.

Only about 25% up in Flat Top since most of the infrastructure is in place and it's already been build and about 75% down in Signal Peak. However, as Jack mentioned a little bit, Signal Peak is a little different. The vast majority of what we had to do in Flat Top, it will be a similar system, just smaller. So the total CapEx spend for the infrastructure will be lower.

From a power standpoint, a lot of the wells, mainly the Wolfcamp D wells will be gas lifted as opposed to running ESP. So we've got a longer time period before we would have to go upgrade the electrical infrastructure, but absolutely putting in the right water handling facilities and having the right gathering for oil and gas will be put in place.

Thank you for that. And then -- sorry, I lost my train of thought for a second. If you think about the Wolfcamp D, can you -- I know previously you all had put a number of locations in slide deck. Can you -- will you at some point update the location counts that you have put out for both Flat Top and Signal Peak?

Yes. Jeff, the numbers that are in the presentation that were put out this morning are updated. But think of the Wolfcamp D as six wells across the section, down in Signal Peak will average closer to 13,000-foot laterals; a lot of these are going to be 15,000-foot wells. But from a density of wells across a mile, it's six wells per mile.

Okay. And then last question, I think on your slide you show the number of feet you all drilled in the third quarter. You have a number at least that would tie to your 2022 capital program to the number -- to the footage you expect to drill next year?

Yes, sir, average footage, again, with the mix that we have, it's closer to 12,000 feet -- 12 to 12.5, and you're looking at two wells per rig per month. So think of it as 24 per rig times [four] at around that $505 a foot for that 13,000 -- [12.5] to 13,000-foot total average lateral link. And now it gives you real close to what we have in our budget.

Okay. Thank you very much.

You bet. Thanks, Jeff.

John White, ROTH Capital.

Thanks. Follow up again on Signal Peak. I know it's early -- the wells that you've drilled and completed plus offset operator wells, h ow are those wells doing? What kind of comments would you offer?

Yeah, John. And again, like I say, we're extremely excited about on, for instance, our Wolfcamp D well had an IP kind of 30 rate of about 850 barrels of oil a day and a peak gas rate of close to $1.5 million a day; especially with today's gas prices that helps kind of juice our returns there a little bit as well. But just on strictly the oil, these are very strong results.

And again, we've got a nice acreage position. The offset operators to our west have -- it's almost a lay down when you look at to the wells that they have online, and they've got some longer-dated wells. Our wells tend to lay right on top of theirs from a performance standpoint. So again, we're very excited about it.

In the acreage that we picked up; we do have three wells that are being completed today that we are non-op in. And so we'll get some more data over on the west side of our acreage block as well.

Okay. Yeah, that sounds like good results. On slide 8, to the southeast of your acreage, there is some white space and to the southwest and to the northeast, there's some whitespace, is -- did some of those areas still in a little bit with the recent acquisition?

No, sir, that is -- we're showing the yellow is the recent acquisitions. Again, like we always say, we're always in the market looking to add things if they're accretive to our portfolio. You can see on this slide, the well that we have drilling to the south to help delineate that as well.

So again, very excited about what's out here. When you talk about what's south of the entire yellow block, that's the [IA10] field. So there's -- it will be very difficult. It's very high densely drilled, very shallow stuff. So there may be some activity they could drill south under it, but you probably won't see a lot of movement further south.

Okay. I really appreciate that detail. Thank you. I'll pass it on.

Jeff Robertson, Water Tower Research.

Just to follow up, Jack, if you look at a lot of the larger companies keeping a lid on their cap on capital spending in favor of distributing cash flow. Does that have any impact on the competitive pressure or a company like HighPeak in terms of either your costs or your ability to look at consolidation opportunities? Has the competitive pressure changed much with the way the companies are trying to execute their plans now?

Actually, Jeff, I don't see it impacting us in a negative way at all. In terms of competitive pressure, we are a growth company. We're not mature. We can't be in a position of just maintaining with an acreage block (inaudible) because we've got to take advantage of the opportunity we see. But undoubtedly, as we go forward, and we build our reserves and build our production. We'd be a lot more attractive for one of the bigger companies to want to acquire us. One of the main reasons is because our performance on each individual well is much better than most of their economics on their big portfolios.

So we have very high profit margin, very big return on investment, and internal rate of return. And but in terms of acquisition, opportunities, and consolidation for us, we look at everything that's out there. There's lots of opportunities in our area, and we just want to make sure that if we do it, that it's dripping off the page, so to speak and going to be accretive to our acquisition opportunities. Other than that, we're going to go slow.

Eventually, we do want to share with our shareholders. We just need to go ahead and get our acreage position to a point because even if at the end of 2022 with four rigs running, our growth profile just continue to drive in 2023 and 2024. I mean, we literally are -- we're so early in the beginning of developing this wonderful asset we have that our focus is going to be to do that to start with. Hopefully that answers your question.

That does, Jack. I appreciate it. Thank you.

Thank you. There are no further questions. I will now turn the call over to Jack Hightower.

I just want to thank everybody for being on the call today. And as you can see that this positioned us for the growth in the future and positioned us for abstaining development program in 2022. And we're extremely excited and look forward to further conversations to let you know the results of what we're accomplishing. Thank you very much.

This concludes today's conference call. Thank you all for participating. You may now disconnect.