HighPeak Energy, Inc. (NASDAQ:HPK) Q4 2022 Earnings Call Transcript

HighPeak Energy, Inc. (NASDAQ:HPK) Q4 2022 Earnings Call Transcript March 7, 2023

Operator: Good day, and thank you for standing by. Welcome to the HighPeak Energy 2022 Fourth Quarter Earnings Conference Call. . Please be advised that today’s conference is being recorded. I would now like to hand the conference over to your first speaker today, the CFO, Steven Tholen. Mr. Tholen, please go ahead.

Steven Tholen: Thank you. Good morning, everyone, and welcome to HighPeak Energy’s Fourth Quarter 2022 Earnings Call. Representing HighPeak today are our Chairman and CEO, Jack Hightower; President, Michael Hollis, Vice President of Business Development, Ryan Hightower, and I am Stephen Tholen, the Chief Financial Officer. During today’s call, we will make reference to our March investor presentation and our fourth quarter 2022 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 and our March investor presentation. I will now turn the call over to our Chairman and CEO, Jack Hightower.

Jack Hightower: Thanks, Steve, and good morning, ladies and gentlemen, and we want to thank you for joining our call today. As we go forward and think about the last year, it’s just amazing that we’ve had such a banner year. But also, I want to emphasize that everybody is aware that we have began our process for strategic alternatives, and we’ll talk a little bit about that today. But I want to just point out that we posted great year-end 2022 results. Hopefully, you’ve had a chance to look at your press release and you can see that our expectations and further substantiate our long-term strategic plan. As I look back on 2022, unquestionably, we’ve had a banner year. We increased our business in a really responsible and multipronged approach, both through the and through strategic accretive acquisitions.

That’s how we on a balanced approach with organic growth through drilling and also through accretive acquisitions. We’ve moved from 61,000 acres at the end of 2021 to over 112,000 acres today. We grew our acreage position, but we also delineated the majority of our acquired acreage in multiple zones across our entire position. We increased our production. We increased cash flow. We increased proved reserves over the past 12 months at rates that no one else in the industry has been able to achieve. And we did this by maintaining a very healthy balance sheet. We also continued to improve our productivity of our primary reservoirs as evidenced by our 2022 vintage wells outperformed our 2021 and 2020 well results. We’re really proud of the fact that we’ve been able to continue improving through our operational efficiency, our learning about how to treat these — this rock in terms of completion and through larger drilling pads, infilled child locations and a higher percentage of wells in our Signal Peak area, which we continue to be very excited about.

We maintain our peer-leading margins and actually increased our cash margins throughout last year as our operating teams continue to make large strides in reducing our lease operating expenses and total cash cost. This is tremendous improvements and continued improvements to be able to do this into the future. I’m really proud of our organization. We have a lean organization. Everybody continues to work hard. Their efforts towards cost reduction on both sides of the equation, maximizing capital efficiency, lowering operating expenses and optimizing well performance, which we were actually one of the few teams in the Permian Basin that are actually improving on our well performance. And the seamless asset integration, which allowed the company to accomplish these milestones in 2022.

It was a challenging year due to many factors, we had serious inflationary pressures. We had supply chain disruptions just like the rest of our peers did, but we navigated through these challenges and actually improved. We ended on a high note, and we fully expect this momentum to continue in 2023. We’re going to stay focused on optimizing shareholder value, optimizing our returns and optimizing our accomplishments relative to our business. The first slide I want to talk about is on Page 4 of the deck and this is similar to our last slide that we talked about in our third quarter, very similar, but I think the important thing is that our production averaged 37,300 barrels a day, which is a 42% increase over the third quarter, a 150% increase compared to last year’s fourth quarter.

That is unprecedented growth. We still have lumpy production. We go up 1 quarter, we maintain the next quarter. We’re going to continue having lumpy production, don’t multiply that 40% increase 4 quarters in a row. But if you just think about, we hit our guidance, we’re going to continue hitting our guidance throughout this year. We exited the year at close to 40,000 barrels a day, which was at the high end of our guidance. We also had somewhere between 1,000 and 2,000 barrels a day throughout the fourth quarter due to some midstream expansion projects. And if it was not for that, we would have surpassed our high end on both our average and exit production guidance ranges. We increased our crude reserves 92% year-over-year to 123 million barrels of oil.

And we continue to expand our acreage footprint, which is now over 112,000 acres with line of sight for additional increases there. So we’re getting good contiguous add-ons as we expand our acreage blocks. We have 2 contiguous acreage blocks with high working interest. We’re set up for long laterals, we’ve been averaging somewhere around 12,000 to 12,500 foot laterals. Our capital efficiency on our development program will allow us to hold our entire acreage position with 1 to 1.5 rigs. As you can see, we had several wells in progress at the end of the year which will all come online during the first half of 2023. Presently, we have almost 57 wells that are in the process of drilling and completion. So that — wells that are already drilled and being in progress are going to substantially add to our production as we go forward here.

We had several additional wells in progress that help us substantiate achieving production guidance numbers. Very — many of these are in other zones. So — and as you can see, looking at financial statistics on this slide, we’re projecting exiting fourth quarter of this year and this is utilizing $90 a barrel, which is a price basically that is being utilized by most of our peers and budgeting purposes or prices, even though we recognize prices are below that right now. And then we exit fourth quarter of ’24 with almost $2 billion in EBITDA. Great improvement as we go forward. The next — Slide 5. I’m going to try to go through these fairly quickly to just hit the highlights on these slides, but Slide 5 is a differentiated growth story that takes us from overspending to actually having free cash flow in this year’s business.

I’ve had people ask me, when is that going to take place? And the answer is we just don’t know because we don’t have a crystal ball as to where oil prices are going to be. But if the analysts and our own internal projections are correct, we will start seeing free cash flow in the second half of next year. We are on course to reach that inflection point with material free cash flow generation. It’s just a function of is it this 90 days, the next 90 days, when is that going to take place? Our asset base has actually grown organically from 0 to 40,000 barrels per day over the past 2 years. There’s no way to prove high rock quality better than exhibiting substantial production volumes. And by executing our plan, at the end of this year, we’ll have an EBITDA run rate of over $1.5 billion at a reasonable oil price.

In addition, we will be positioned to continue increasing our production next year and with a reasonable growth rate similar to the rig cadence that we presently have. And that gives us roughly $1 billion of free cash flow on a $90 price per barrel in next year’s business. At that point in time, our free cash flow yield and investment rates will compete with anyone in our industry. So as you can see, I’m very excited about what’s taking place in the company, and I’m going to turn the call over to Mike now to talk about our margins and provide you with an operational update. Mike?

Michael Hollis: Thanks, Jack. Now turning to Slide 6, margins. It sounds like a broken record, but our BOEs are not the same as everyone else’s. We continue to expand our margins differentially to our peer group. Our fourth quarter margin per BOE was 47% higher than our peer average. This theme will remain over the coming quarters as natural gas prices stay depressed. Don’t forget the gas prices in the fourth quarter were higher than what we’re seeing today. With our high oil mix, high peaks margins will expand even further compared to our peer group next quarter. On a relative value basis, our average peer would need to produce about 60,000 BOEs per day to achieve the same cash flow results that we do with 40,000 BOEs per day.

And in today’s market, a company that produces in line with 60,000 barrels a day, it’s typically viewed much differently by Wall Street than . Size matters, but I disagree with that thought process, the impetus should be on efficiently converting oil and gas into dollars and cents, and that is exactly what we focus on at HighPeak. Although we’re very bullish on oil prices long term, in the short-term price volatility and looks like it will continue. So we are very fortunate to produce such valuable barrels, which will help us remain financially strong even during periods of price volatility. So in addition to our BOEs being very oil-rich and highly profitable, we continue to drive down our operating costs, which will further increase our core cash cost.

All-in cash cost per BOE continues to decrease. We reduced our LOE 15% quarter-over-quarter. Now in the fourth quarter, G&A was a little higher due to year-end bonuses, but it’s reasonable to expect that it will continue to drop as evidenced by our previous quarters. We continue to keep a lean and efficient workforce as volumes increase. And as the denominator grows, the fixed cost will continue to be diluted, again, expanding the margins. This is a great time to throw a shout out to our HighPeak organization. 2022, as Jack said, was a great year for our company and none of this will you make what we do easy. Thanks. We continue to drive operational excellence in all facets of the business. We are continuing to remove costly generators. Our fixed costs continue to reduce as our production increases and building infrastructure and Signal Peak, which will further reduce our cost in that area of the field.

Our margin per BOE is the best in the business and will continue to expand, further differentiating HighPeak from our peer group. Now turning to Slide 8. ESG. We’ve been very transparent with our goals and initiatives. Fortunately, for us, we were the original architect of our position. We were able to set up everything with efficient operations and environmental stewardship in mind. Power. We run a very energy-intensive business, so it’s imperative that we’d be efficient, clean and scalable. We oversized our substation which allows another rig or 2 to utilize high line power up at Flat Top. And we’ve also added another frac crew in fuel. Facilities, we build very large-scale central tank batteries that minimize our footprint and make for adding additional wells cheaper and more environmentally friendly to connect.

Recycle. We continue to recycle high levels of our stimulation fluids and are expanding our recycled capabilities across both large acreage blocks, reducing cost and the need for makeup water. Sand. We now have 3 frac crews utilizing local wet sand, which greatly reduces our emissions and costs. All of our ESG initiatives are both financially and environmentally rewarding for our shareholders. High Peak looks at these initiatives as just doing the right thing. Now turn to Slide 9, Flat Top operational update. East Howard County has always been plagued by the reticence of some as to whether we have good rock and enough inventory in multiple formations. The work we’ve done to date demonstrates very robust economic results across the entirety of the block.

From the Northwest to the Southeast, and from the southwest to the northeast. The , bullet #1, extended the Lower and Wolfcamp A into County. Four miles northeast of our main development area for the Wolfcamp A and almost 7 miles east of our existing Lower Spraberry wells. And both of these Conrad wells are performing similar to the development in the core of the Flat Top area, again expanding the footprint for our inventory. , bullet number two, a 4-well stacked lateral pad with a Wolfcamp D as in David, 3-finger tests and a Wolfcamp B as in beta test plus a lower Spraberry and Wolfcamp A. These wells provide multi-zone support for additional inventory down in this area. The Griffin pad bullet #3. It’s a 5-well pad Three Wolfcamp A’s and 2 Lower Spraberry wells, again, solidifying that the Lower Spraberry and the Wolfcamp A formations are good across our entire Borden County acreage.

Southeast Flat Top area, Bullet #4, the red box, has demonstrated similar well results to the wells back to the west, again, giving us confidence in this area as well. All of these results give line of sight to the inventory runway and ability to continue to efficiently grow HighPeak’s productions. Highpeak surface Bullet #5, houses our field office, our 1 million-barrel recycle facility and home to the solar farm. If you’ll turn now to Slide 10, Signal Peak operational update. There’s a ton of exciting activity going on at Signal Peak. HighPeak has previously delineated the base, lower Wolfcamp D across the entire block. We are now producing 26 wells in the lower base Wolfcamp B. We continue to delineate the Wolfcamp A and the Lower Spraberry as shown with bullets 3, 4 and 5.

Multiple 3-finger Wolfcamp D and Wolfcamp C are in progress as shown with bullets 1 and 2. We are expanding our recycled capabilities and overhead electric power system which will continue to drive down our lifting cost. And we are excited and look forward to sharing these results from our upside wells and locations in the coming quarters. I’ll now hand the call back over to Jack to discuss our year-end reserves.

Jack Hightower: Thanks, Mike. The next slide on Slide 11 gives you our year-end proved reserve summary and as I mentioned earlier, we’ve had phenomenal success over the last 2 years as evidenced by 130% compounded annual growth rate of our proved reserves. Remember, though, that our BOEs are different, and they currently have 47% higher margin than other reserves from our peers. Our reserve replacement ratio in ’22 was 550% through the drill bit, not including acquisitions. And if you look at our ’22 acquisitions, our replacement ratio then increases to over 750%, unprecedented in my 53 years in the business in terms of growing. Of course, if you didn’t have any reserves in well and it was a discovery, it was a tremendous growth.

But when you now consider that we have over 220 wells drilled to continue with this growth process, That’s the thing that substantiated and you can have expectations in the future to continue doing this. Our trajectory of proved reserve growth will continue. We’ve fully seen of total resource potential for these assets consider that we have over 2,500 locations. And we have intentionally been very conservative in our annual reserve booking process we’re not changing anything. It is not broken just continue being conservative at 6% of original we’re not booking reserves from one end of the field to the other. We do step outs, very conservative. And keep in mind that in any 5-year period with outside engineers. It doesn’t matter if it’s Netherland and , Roger, Scott, , our own internal engineers, you can go right down the list, you have almost double reserve success, especially over a period of time with each 5-year period of technological improvement.

Our reserves are going to continue going up. Our recoveries are going to continue going up technological success. And we’re also improving return deliveries and we’re improving on deliverability, the turn on investment parameters being better and better and better as we go forward in this. So we’re going to continue being conservative on our booking process, but we’ve got a lot of meat left on the bone so to speak. For the next slide to look at is — and I mentioned this once before that we wanted to compare our area in Eastern Howard County to Western Howard County, more in the — as we go deeper into the basin and more compared to some of our larger peers in the area. We’ve talked about our reserves, how fast they’re growing, but Eastern Howard County is a very active area and the margins are differentiated from other areas of the basin.

At the end of the year, our of the Eastern compared to western and looking at results from 2020 onwards shows is actually outperforming the West on a recovery factor of oil prices. In addition, HighPeak is outperforming its peers, its peers in the county. We now have over wells drilled and our results are over 500,000 barrel recoverable compared to 471 of our peers in the West. We’re almost 10% higher on EUR and almost 10% higher on economics, not counting consideration of having a higher oil cut. One of the local newspapers in Midland, the Midland reporter telegram announced in the last few weeks that Howard County is the fastest-growing producer of oil in the entire United States and Howard County has now moved into the #3 position in the Permian Basin as far as oil production.

So we’re in a great area. It’s going to continue improving as we go forward. And these results are indicative of our success in Southern Borden County as well. As Mike previously walked through our delineation of Lower Spraberry and Wolf A in this area, that’s going to increase additional shareholder value. So we’re not just buying leases to buy gold pasture, so to speak. We’re buying leases and expanding our footprint and as we drill it up, it’s becoming very commercially successful. In fact, both of those wells are making over 800 barrels a day now. So we’re really excited about that area. The next Slide 13 just shows our inventory, and it gives us a sense of with running a forward program with 1,300 primary locations, we have over 14 years of primary inventory runway.

Every time we make a presentation in 30 days, we have 10 more wells in and we’re delineating other zones now. And so when you look at this, chart, you see all the way from the Mill Spraberry all the way down to the Wolf B, and that includes the Wolf B 3 fingers and also the zone. We are developing all these zones now, and we’re going to have a lot more information and some of our offset operators are also drilling in these zones, up in the Middle Spraberry and the . So we have expectations to be able to continue going forward with upside formations, and we hope that several of these upside locations will add to our primary count within the last — within the next few quarters as we see the results of these wells. I mentioned earlier that our locations are averaging over 12,000-foot laterals now, we have the opportunity to do that because of our contiguous acreage block.

A lot of our peers have more acreage inventory but it’s unattainable acreage. It’s very difficult for them to put units together to deal with pooling problems and to deal with other companies and arguments as to who’s going to operate what pipeline is a well going to sell into? What are the marketing characteristics who has better marketing, we control everything in our area. So we have the choice to drill and to space our wells primarily best that gives us the maximum shareholder return and ultimately leads to higher free cash flow generation. It’s why 40,000 barrels is equal 60,000 barrels with our peers. So in Slide 14, this is an exciting slide also. We messaged in January press release that we plan to step down from our 6-rig program, which we were running in the second half of ’22 to running 4 rigs throughout ’23 and ’24.

Many things considered that, not because we don’t have the results of drilling activity. We want to keep a strong balance sheet. Oil and gas prices went down during that period. We have a higher number of wells that we expect to turn in line this year with 57 wells in progress. The backlog of those wells in progress that we built while running our 6-week rig program last year, and this point is the primary reason for the delta in our CapEx budget in ’23 compared to our forecasted CapEx budget in ’24. We didn’t want to overdrill. We wanted to get maximum return on investment. So we’re being conservative with the development of our pads and with our spacing program. Our unit cost per BOE, which is already very competitive with our peers, is going to continue to increase and will further expand our peer-leading margins.

This wasn’t by accident. This was a planned program all the way throughout in the way we have always differentiated ourselves from our peers to have higher return on investment and higher internal rates of return. The key point of this slide is to show where we’re going. We’re going to become free cash flow, and it’s going to be a free cash flow machine. I’ve had investors ask me, well, when is that going to happen? Well, if I knew exactly when prices are going to be projected, I will be able to say when that’s going to happen but I’m comfortable that it’s going to happen in the second half of this year. And next year, we’re projected to receive to achieve free cash flow at a breakeven all the way down to $45 oil, that is unprecedented, most companies can’t even get their money back or have any kind of profit at $45 oil.

If oil prices stay around $90 a barrel, we estimate our free cash flow to be in excess of $1 billion in 2024. This will allow us to completely pay down 100% of our outstanding debt next year. If we chose to do so, we could also increase our drilling program and prices stay in that $90 to $100 range, but the point is we will have excess free cash flow available on our balance sheet. So our investors can look at that and be excited about what’s happening over the next 12 months or so. Even though I know Wall Street is usually quarter-to-quarter. We take a little longer-term view. And on a separate note, I want to share with our shareholders to know that we are constantly monitoring the market volatility in commodity prices and service costs. We have the ability to be flexible with our drilling program.

We could either increase or decrease our program, if necessary. We don’t have any long-term contracts that can effectively mess us up, so to speak, and cause us to have what I call the perfect storm, high interest rates and low oil and gas prices. We’re going to continue with that program. So in closing our last slide 15, this has kind of encapsulates what we’ve always talked about, contiguous acreage inventory, consistent well results, operational and environmental focus, leading margins in free cash flow and growth. But looking at the value proposition here, you should look at this, and it kind of tells you why you should own HighPeak stock and to hold on to your stock for the ride relative to us continuing with our strategic alternatives.

We have a large contiguous acreage position, providing for maximum capital efficiency. We have a tremendous amount of inventory debt where we’ve now proven the rock quality of this area. An inventory like this is a huge scarcity in our area. In fact, just noticed where one of the CEOs recently said it looks like the Permian is that peak production for only 5 years here. Our inventory is defined by consistent high-return results across more than 200 wells that we drilled today. Our development program is environmentally sound and physically rewarding, our high oil cut and low-cost operations truly lead to a differentiated peer-leading margins and these things lead to our projection of generating large amounts of free cash flow for years and years and years to come.

All of that is from 1 vantage point today. In addition, we continue to improve all aspects of our business from repeatedly decreasing our lease operating expenses, improving our well performance and improving the number of formations that are economically sound, providing for long-term return on investment and additional upside to exceed our expectations. Considering these points, this is an extremely confident are confident in our ability to optimize shareholder value. That’s what everything is about and to continue operating in the future and implementing the process for strategic alternatives. We talked about that process. It’s a process providing optionality relative to merger relative to outright sale relative to refinancing and equity increases to increase shareholder value.

So with that now i’ll turn the program over to questions. If anybody has any questions, we’re glad to answer now.

Q&A Session

Operator: . Our first question will come from John White of ROTH MKM Capital.

John White: Congratulations on some very, very strong results. On the front page, I want to make sure I’m reading things right. On the front page of the press release, you say you extended development potentially to the Lower Spraberry into Borden County based on 3 Lower Spraberry wells. Are those wells addressed later in the presentation, the Conrad and the Griffin pads?

Jack Hightower: Yes, John. I mean, Mike will elaborate further, but it’s always — it’s from the western part all the way over to the eastern part of the Conrad and Griffin wells, but go ahead, Mike can answer that.

Michael Hollis: You bet. Yes, John, as we’ve picked up acreage up in the Borden County, the operating acreage that we picked up kind of that 6,500 acres, it was kind of our first 4-A and that we put on multiple acquisitions and leases from . Most of that was predicated and underpinned by the Wolfcamp A activity that we have seen. You can notice that we’ve got much — many more brand sticks drilled up in that area. The Wolfcamp A is phenomenal. It looks just like down south in the Flat Top. But as we started developing the Lower Spraberry and saw the results in Flat Top, the rock looked very similar up on this acreage in Borden. We extended up into where you see the bullet #3 on the Griffin pad and drilled 2 Lower Spraberry wells, wine rack with the Wolfcamp A.

Those 2 wells look almost like a lay down to the Wolfcamp A in the area. So again, very encouraging and added an additional zone to that entire area. So then we stepped all the way out to where the Conrad is about 7 miles west or east of where we drilled the Griffin pad. And as Jack mentioned, the Lower Spraberry and Wolfcamp A there are phenomenal. One is doing over 900 barrels a day and — and that’s just oil and 1 over 800 and it’s very early in the cleanup cycle. So again, it gives us confidence that we can go in and infill between the 2 development areas and it’s roughly another 75, 80 wells that we can feel very confident that in 2023 and ’24, we’ll be able to go to build that very machine-like development, very low cost, efficient and continue to drive these margins of.

John White: And looking on Slide 10, all the pink sticks for the Wolfcamp D, it looks like your confidence is increasing in the development of that zone in

Michael Hollis: Yes. Yes. The pink sticks on Slide 10 are the lower base Wolfcamp D, so we’ve drilled those across the entire acreage block. So very confident in the results we have with the lower base. We have seen some of our peers to the west and to the north of us. Drill a little shallower in the Wolfcamp B zone. We call it the 3 fingers. There’s 3 little streams on the log that we’re able to see much more brittle, should hold a frac better all of the geomechanics, geochemistry, analysis, all lend itself to suggest that those wells will be even better than the lower base D. So what we’ve shown here on the chart is where we’ve done the 3-finger test. We drilled some of the wells. We fracked some of the wells and look to have results here in the next month, 1.5 months.

So over the next few quarters, we’ll be able to update you on that shallower zone of We also walked through some Wolfcamp C tests, very similar in nature. We’ve got 1 drill out about to come online and a couple of others that we’re drilling today. so that we’re, again, give us another quarter or 2, and we’ll be able to present to the Street. And like Jack mentioned, hopefully, we’ll be able to move those from upside locations into our primary zone, our primary locations, again, just extending that runway of high rate of return inventory. Something that we’ve talked about in the past is the Wolfcamp A and Lower Spraberry. These all look very due to lower spread back. and 3 different test areas that we’re drilling and completing those wells, little bit about the top line.

So again, the next few quarters are going to be very for the inventory to be the difference in to that 20-year rate to be able to keep these kind of returns that we’re showing today.

Operator: . Our next question will come from Jeff Robertson of Water Tower Research.

Jeffrey Robertson: Mike, on the Slides 9 and 10 with some of the pads you’re showing, are any of those results additive to the inventory counts you show in a couple of slides later in the deck. And secondly, are you testing anything over the next couple of months that’s not included in the locations that you show on the inventory side?

Michael Hollis: So Jeff, all the locations that we have are in our inventory mix that we have shown in both the primary and the upside locations. What’s going to happen here is as these wells are developed and prove up those zones. Again, we had to — we were very, very conservative on those upside zones and what we felt that they may be able to provide. So again, with all of the all of the data that we have collected and what we truly expect out of these zones, they will absolutely move up into the primary numbers. So it will increase the primary numbers. But as far as adding to the total of the 2,500 that we have, all of these wells are captured in that. Now over time, as we develop more of these the areas that we had picked for where they would be upside will most likely expand and you’ll see some growth in that 2,500 number. But that’s kind of how we’re attacking it, Jeff.

Jeffrey Robertson: So it’s based — it’s just continued derisking from the upside to the primary to move categories.

Michael Hollis: That’s correct. And again, every time you go step out, you tend to move the box around where you thought an upside zone would be prospective.

Jeffrey Robertson: A question just on delineation between — that you show on Slide 12. Jack, you mentioned, I think, a 6% recovery factor that called using your reserves. How does recovery factor on flat top and/or signal peak compared to the more central part or the western part of Howard County.

Jack Hightower: Jeff, that’s a great question because everybody uses different recovery factors internally for their reserve bookings. It’s typical for the majors to use that 6% recovery factor. Some of the smaller mid-cap companies to compare Western to Eastern is about a 2% difference running from 6% to 8% recovery factor. But as you can see, in evaluating 20 something wells out to the west to 1,700 going very quickly up to 1,800, 1,900 in the next 12 months. East is actually performing — outperforming the wet. But the typical difference on a macro scale is about 2% difference, about 25% plus difference between West and East in terms of recovery factor and in terms of the size of the companies. But our — we know it’s going to increase and many companies are using up to 14% recovery factors even in our area.

But we’re just — we’re going to take a conservative approach and we’re going to go with what we have as factual right now and use a conservative recovery factor. We can always add to and it gives a potential buyer the opportunity to book whatever they want to book in terms of reserves. We don’t have to worry about revisions and write-downs and impairments. We’re just going to take a conservative approach and as long as we’re getting a 150-plus percent increase on an annual basis, it doesn’t really matter. As we delineate this year, it could be even higher recoveries because we might decide to step out further and have more PUD development than we did in this year’s business. Hopefully, that is

Jeffrey Robertson: It does. With respect to the revisions in this year’s reserve report, I think before you all had shown maybe a 5 to 6 rig cadence from 2020 — maybe beyond 2023. Is some of the revision to year-end reserves just related to how you’re stacking up the current plan for 5-year development that was included in the December report.

Jack Hightower: Yes. I mean it’s very nominal anyway. And it’s just a function of what we were in going to be drilling versus what we ended up designing to drill. And it is — it’s very conservative. We didn’t consider that. We considered mainly just maximize the shareholder value and keeping a strong balance sheet.

Jeffrey Robertson: Last question. If HighPeak chose to drill more over ’23 and ’24, maybe just think about ’24 and not be as conscientious about generating free cash flow from this asset. Mike or Jack, do you have an idea of what you could do not to outrun the existing infrastructure on this acreage space in terms of the number of rigs you might be able to run or how you think about operating?

Jack Hightower: We actually have — at Flat Top, we have increased and added to our infrastructure, and of course, we have the ability as we drill additional wells out to the East. We are improving that infrastructure, we’re improving our unit system and our tank battery system we designed everything with the ability to expand particular tank battery facilities. So if we decided to go back to 6 or 7 or 8 or even 10 rigs, with what we have planned in 2023 with Signal Peak, we could actually accommodate that without having to make major changes to our infrastructure. It would just be common add-ons that would fall into the $20 million to $30 million expenditures to add additional production. It’s all now planned, Jeff, into the future to even meet — almost doubling the capacity of our rigs.

Jeffrey Robertson: Check, that’s we’re having a continuous acreage in being basically the original developer of these zones on this acreage gives, a real infrastructure advantage to future development.

Jack Hightower: No question. That is a major component of our position. We’ve developed this not to be critical of private equity but to be in consideration of building something long term for the future as a major company development that would make this an attractive asset to give optionality for a potential purchaser where they can control their destiny because the profit margins are so great here. They literally could move drilling rigs into this area and be able to improve on and improve their production and return on investment by focusing some of their capital in this area and growing it if they wanted to do so. They would have that luxury to do that.

Operator: And I am seeing no further questions in the queue. This will conclude today’s conference call. Thank you all for participating. You may now disconnect, and have a pleasant day. The conference will begin shortly.