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

HighPeak Energy, Inc. (NASDAQ:HPK) Q4 2023 Earnings Call Transcript March 7, 2024

HighPeak Energy, Inc. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good day and thank you for standing by, and welcome to HighPeak Energy 2023 Fourth Quarter Earnings Call. [Operator Instructions]. Please be advised that today’s conference is being recorded. I would now like to hand the conference over to your speaker today, Steven Tholen, Chief Financial Officer. Please go ahead.

Steven Tholen: Good morning, everyone, and welcome to HighPeak Energy’s fourth quarter 2023 earnings call. Representing HighPeak today are Chairman and CEO, Jack Hightower; President, Michael Hollis; and I am Steven Tholen, the Chief Financial Officer. During today’s call, we will make reference to our March investor presentation and our fourth quarter 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 in our March investor presentation. I will now turn the call over to our Chairman and CEO, Jack Hightower.

Jack Hightower: Thank you, Steve, and good morning, ladies and gentlemen, and thank you for joining us today. If you’ll turn to page 4 of the slide presentation in the March investor deck, that’s where I’m going to begin the presentation. As mentioned in implementing our corporate vision, 2023 was absolutely a transformational year for HighPeak. Just to look at what we accomplished in ’23, we reached a production milestone of over 50,000 barrels a day. We grew our average production rate by over 86% from ’22. We exercised capital discipline by reducing our rig count as commodity prices pulled back. We strengthened our balance sheet and our liquidity position with our debt refinancing in ’23. We reached two additional major milestones when we became free cash flow positive and generated over $1 billion in annual revenue.

With a transformational ’23 behind us, we now focus on ’24 being a year of realization for HighPeak, the year where we focus on free cash flow generation, paydown of debt, and returning value to our shareholders. Now turning to slide 5. We’re going to outline our core values and how we’re going to create additional shareholder value. We will continue to exercise disciplined operations. Our two rig program will allow our operations team to be laser focused on optimizing our capital costs and to continue driving down our operating expenses. We will also continue to organically increase our acreage position through the ground game in areas where we have expanded the delineation of our primary zones. From a financial perspective, we will remain focused on generating free cash flow, which will be earmarked for debt paydown and provide us with a nice liquidity cushion going forward.

In addition, we will look to maximize shareholder value through our recent 60% dividend increase to an annual rate of over $0.04 per share. Our recently announced opportunistic share repurchase program and an additional acreage acquisitions and ultimately through our strategic alternative process. Now turn to page 6, and we’re going to talk about some of the company highlights. Focusing on production levels for a moment in the fourth quarter, our sales volume averaged over 50,000 BOE a day. Our fourth quarter production volumes were negatively impacted by weather issues and unforeseen midstream maintenance interruptions, which totaled over 3,000 barrels a day, in addition to our frac hits that just normally happen on a monthly, but our day-to-day monthly basis as we frac additional wells.

So far during the first quarter, our operations have been running smoothly and weather-related impacts have been fairly minimal as evidenced by our current production rate of approximately 50,000 barrels a day. I’d also like to take this opportunity to point out that although we reduced our development plan from six rigs to two rigs during the middle of the year, we were still able to hit both of our 2023 annual production guidance after factoring in fourth quarter production impacts and our annual capital budget. This is a testament to the quality of our asset base and the caliber and dedication of our operations team. I’d like to now draw your attention to the red line on the map, which highlights our newly acquired acreage in northern flat top.

We’ve increased our acreage position by over 18,000 acres in northern flat top moving from roughly 114,000 to 132,000 net acres now, majority of which is located in this area where we have continued to have success in our primary zones moving north. We remain very excited about our recent well results from this area, which are consistent with the performance in our core flat top area, almost 200 additional locations over our — in our primary operating zones. Even considering under financial highlights, the slightly reduced sales volumes and lower commodity prices during the fourth quarter compared with the third quarter, our quarterly EBITDAX still approximates $1 billion annual run rate. We ended the year with a very reasonable leverage ratio of one times net debt to fourth quarter annualized EBITDA.

We generated additional free cash flow during the quarter of about $34 million, and that brings our total second half 2023 cash flow to approximately $110 million. As I previously reported, we also increased our quarterly dividend by 60% to over $0.04 a share, and we authorized a $75 million opportunistic share buyback. Now turning to slide 7. This gives the established proven position of HighPeak now in the Midland Basin. As a player, it is established now and shows a history from 2020, all the way up to — through 2023. We consummated our business combination in 2020. We started with minimum production. And over the past few years, we have increased our production as quickly as I have ever witnessed any one organically grow production during my 53 years of history in this business, while also establishing eastern Howard County as a core oil producing area of the Midland Basin.

Looking forward into 2024, our capital efficiency will continue to improve as we maintain focus on co-developing our primary reserves and primary zones in the Wolfcamp A and Lower Spraberry. Historically, we have flexed our development plan up or down depending on commodity prices and return on investment. We will make sure that as we adapt to various pricing environments, we will be slow on the gas and quick on the brake. And you can demonstrate how easy it is as we increase the rig count to increase our production with the wonderful inventory we have in place. As I always say, this business is about location, location, location, and our ability to grow the business with this trajectory is the ultimate proof that our ROC in this area is excellent.

Now turning to slide 8, let me talk a little bit about our year end proved reserves. As noted, you can see that we continued to significantly increase year over year with 2023 growing 25% compared to the prior year and from ’22 to ’23 over 30%. So we’ve had consistent almost 30% growth for the last two years. We have over 90% liquids proved reserves stack, which absolutely differentiates us from all our public peers. This provides HighPeak with higher operating margins, especially during this period of relatively low natural gas prices. Over the past three years as a public company, we have achieved a 90% proved reserves compounded annual growth rate, almost entirely through the drill bit unprecedented. Our 2023 reserve replacement ratio was almost 300% and we grew our total proved reserves to 154 million barrels in spite of the SEC price dropping close to 20% year over year.

I will remind everyone that we are very conservative in the way we book our PUDs. In fact, of our total primary locations, less than 190 locations are booked as PUDs. So we have substantial additional reserve value that is not captured in these numbers, and we have significant additional inventory that we will cover later in the presentation. And now I’m going to turn the presentation over to Mike Hollis, who is our President to discuss operations and corporate efficiency. Mike?

Michael Hollis: Thanks, Jack. Now turning to slide 9 to discuss our margins. HighPeak stands alone amongst our public peers in margin per BOE. As I’ve mentioned in the past, not all BOEs are created equal. Our high oil cut drives differential margins for our shareholders. As one would expect with natural gas prices trading at historical lows and our high cash operating margins are continuing to walk further away from our peer group in HighPeak favor. Our unhedged fourth quarter EBITDAX margin of $53.20 per BOE was 68% higher than our peer average margin of $31.69 and 30% higher than our closest peer. At HighPeak, it’s in our DNA to pursue excellence and drive our costs down. Our efficient operations and utilization of our company-owned infrastructure will continue to drive margins higher.

As a comparison to equate the same EBITDAX generated by HighPeak’s high oil cut 50,000 BOEs a day in the fourth quarter, our average peer would have had produced approximately 84,000 of their BOEs to generate the same EBITDAX. In my opinion, HighPeak’s margins will continue to dominate the peer group over the next handful of years as natural gas and NGL prices continue to face headwinds. We are extremely fortunate to have access to such a sought after an extensive inventory of oily rock. Now turning to slide 10 to discuss our operations. Efficiencies enhanced free cash flow generation. There are three pillars that drive corporate returns and free cash flow generation. They are number one, high-margin oily production and having significant inventory of great rock to drill.

Number two, keeping your operating costs low, having a laser focus on driving efficiency. Number three, continue to drive future CapEx cost down dollars per lateral foot completed needed to hold or grow your production. HighPeak checks all of these boxes. I will address each of these pillars on this slide. Pillar one, the map in the center of the slide highlights the 2023 activity to date. Note the dark blue sticks. They blanket the two acreage blocks completely. We increased our production in 2023, 86% year over year with this activity. The oil in the stock tank is proof that the rock is good. As Jack mentioned earlier, we have added 18,000 new acres in our northern flat top areas that we are extremely excited about. This new acreage lies adjacent to an area where we have significant existing PDP wells, both in the Wolfcamp A and lower Sprayberry zones.

We have already drilled a well on the new acreage and additional logging, cuttings, and petrophysical analysis suggest the oil in place is as good or better than our core flat top area. And we look forward to discussing this production in upcoming calls. And as denoted on this map, you can see where our two rigs are currently located. Now, pillar number two, driving op costs down. On the left-hand side of this slide, you can see our LOE performance throughout 2023. You may ask what are some of the drivers of this performance. I have to give credit to the operations group for focusing time and effort to maximize production uptime of these wells and reduce failures, also optimizing field-wide chemical programs by taking a holistic approach through the full lifecycle of the wells and by more fully utilizing HighPeak’s world-class infrastructure.

I’m proud to show the inset picture of the HighPeak solar farm. These panels are up and the tie-ins are being made. Electrons are expected to flow in May. This will further reduce our power costs, driving down LOE and also minimizing our carbon footprint. I look forward to being able to say we are drilling all sunshine this summer. Now pillar number three, capital efficiency. On the right-hand side of this slide, you can see our historical DC&E cost per foot. The industry enjoyed historical — starkly low corporate cost during COVID. Unfortunately, we also had low commodity prices as well. In the post-COVID era, there were extreme inflationary pressures stemming from supply chain constraints and rapid industry-wide acceleration of activity.

Now post COVID to date, we have seen capital cost trend significantly lower, roughly 25% from the hIgh teens. Now I want to draw your attention to the star on the chart. This represents our third quarter 2023 actuals. This is the dollar per foot that we budgeted for 2024. We are adhering to and under-promise over-deliver philosophy. Currently, we’re seeing high teens DC&E costs running approximately 7% below those numbers budgeted for 2024. We generated $110 million of free cash flow in the second half of 2023 and went into free cash flow mode. Any dollar saved is an additional dollar contributed to free cash flow, further enhancing HighPeak shareholder initiatives like debt repayment, dividends or stock buyback. Our 2024 budget is slightly front half weighted due to carrying in of DUCs from our 2023 program.

As we exited the year, running three rigs, our infrastructure projects that tie in our newer acreage will also be somewhat front half weighted. The right ROC, productivity, and oil mix with low-cost operations, efficient deployment of capital, drive corporate efficiency and enhanced free cash flow generation. This put HighPeak in an enviable position to drive shareholder value. Now turning to slide 11 to discuss our inventory. As shown on Slide 11, HighPeak has over 1,700 drilling locations in what we consider to be our primary zones. In our bread and butter, Wolfcamp A and Lower Spraberry zones, we have close to 15 years of inventory at our current development base. I would also like to point out that we are not only organically able to grow our production 86% year over year in ’23 and not only replenish our inventory, but we increased the number of drillable locations in our primary zones at the end of 2023.

We ended ’22 with a little over 600 locations in the Wolfcamp A and lower Spraberry. And at the end of ’23, we now have over 700 locations in those two benches, even after drilling approximately 85 wells into those zones during the 2023 calendar year. Counting the Wolfcamp B and the Wolfcamp D, we add another two decades of running our inventory. Our upside targets in the middle Spraberry and Wolfcamp C push our runway out to close to half a century. We’re blessed to have decades’ worth of oil rich, low cost, high margin inventory, which we will be able to economically convert to free cash to return to shareholders. Furthermore, some of our upside zones are currently being drilled and delineated by our direct offset operators. We are extremely excited about some of these initial results, and we enjoy being the beneficiary of this potential upside without HighPeak having to spend the risk dollars at this stage.

Finally, I’d like to take this opportunity to thank our geology and land departments for their hard work over the last year. In a market environment where high quality inventory is extremely scarce and companies are paying top dollar for that remaining inventory, our team was able to identify organically acquire high value locations, setting the stage for HighPeak to deliver exceptional returns to shareholders. And with my comments now complete, I’ll turn the call back over to Jack to discuss this year’s development plan and guidance.

Jack Hightower: Before we turn to slide 12, I’d like to take this opportunity to throw some much deserved appreciation to our operations team. They did a fantastic job of navigating our field operations last year and quickly and efficiently adapting to the changes in our rig cadence. It wasn’t easy, going from six rigs back down to two rigs, while helping us still achieve an 86% growth in production last year. We’re truly blessed to have such a great operational team. Now turning our focus on slide 12. Looking into 2024, we designed our program around two rig, one frac crew development cadence this year. Our plan will remain focused on high return co-investment in our Wolfcamp A and lower Spraberry zones in this current commodity price environment.

We may also decide to drill a few wells into some of our upside zones if we continue to unlock what we see from our offset operators, which is pretty exciting right now in various zones. We reduced our development plan to two rigs in early February and are currently running one frac crew with the additional carry in wells that Mike mentioned in our two rig program, we will be able to fully utilize one frac crew during this year’s business. Approximately 90% of our capital will be invested through the drillbit this year. In future years, that percentage will increase as the need for infrastructure spending will reduce to about 50% of this year’s budget. Even with the addition of the acreage, the infrastructure is very efficient and is almost 100% in place.

And as Mike previously discussed, we feel that there’s additional savings that we may potentially realize this year on both CapEx and operations sides of the equation. We provided an unlevered free cash flow sensitivity chart based on consensus oil prices ranging from $70 a barrel to $90 a barrel. From a high-level view, a $10 barrel increase in oil prices, it equates to over $100 million of additional free cash flow. There’s no question that we have proven the capability of our asset base to increase production levels quickly and economically. However, given the current commodity price environment, which has been fairly volatile over the past few months due to various geopolitical tensions, anticipated interest rate movements and fragile economies, we’ve seen oil prices move around from the high 60s to the low 80s.

In the current market, we feel that the best development plan is to maintain production at ’23 levels and focus on free cash flow generation and debt reduction. However, this does not preclude the opportunity to increase activity levels in the future if prices stabilize at a level that justifies additional activity. I’ll do want to emphasize to everyone and reiterate that we will always look to run our program within our operational cash flow on a go-forward basis. Now turning to slide 13, and this goes to the scarcity of quality inventory that has been driving M&A activity. It’s no secret to anyone on today’s call that there’s a huge wave of M&A activity taking place within our industry, especially in the Permian Basin. And the underlying reason for this scenario is due to the scarcity of remaining high-quality drilling inventory in high-return areas like the Permian.

This situation is not just a fear factor. It’s reality. The US has grown its domestic production levels considerably over the past decade at an unprecedented pace, we’re reaching a point where the growth pattern is beginning to level off. And at some point, in the near future, it will actually start to decline. It’s my belief that this scenario will happen faster than most of the experts are currently predicting. I think you will start to see degrading capital efficiency and almost all shale basins over the next few years as tier one inventory is exhausted and current development cadences. We are fortunate and happy that we have close to 1.5 decades of delineated high-return inventory, especially at our two-rig cadence. Even with increasing rigs, we still enjoy tremendous long-term inventory.

In addition, we enjoy a large controlled acreage position with very few non-operated partners, which facilitates the drilling of long lateral wells and efficient build out of infrastructure. This gives us complete total control of our own destiny. We absolutely have differentiated oil-weighted, high-margin production and reserves, something that will remain extremely valuable over the near to medium term as natural gas prices continue to face major headwinds. We spent the time, effort, and capital to build out an infield and infrastructure system that is truly world-class. This system allows us to continue to realize additional cost savings, facilitate our ESG goals, and flex our activity levels up or down without overrunning the system. All of these attractive attributes make us firm believers that HighPeak is in an attractive position relative to current M&A activity.

Turning to slide 14, to wrap up, our key takeaways are that ’23 was definitely a truly transformational year for HighPeak, and we’re continuing to carry positive momentum going forward into ’24. We accomplished the major goals that we set out last year, which positioned us as an established player in the Midland Basin. We achieved our annual production guidance even taking into account the reduction of our rig count and our curtailed production volumes. We reached the free cash flow inflection point milestone. We quickly and efficiently adapted our program as commodity prices merited and have designed our ’24 program based on capital discipline and focused on capital efficiencies, free cash flow generation, and debt reduction. We fortified our balance sheet with providing us with additional liquidity and flexibility and no near-term debt maturities.

We reduced our costs across the board, both on CapEx and OpEx sides of the equation, and we have line of sight to additional savings in 2024. We recently enhanced our value — return of value to shareholders with a 60% increase in our quarterly dividend and authorized an opportunistic share buyback program. In addition, in light of current market environment, we have reengaged our strategic alternatives process. Due to all the positive things I just mentioned. I’m extremely excited about what ’24 will bring to our shareholders. And so now I’m going to open up the call to questions from our analysts. And one question that I’ve already had that I think is important to emphasize is if your production is going to maintain flat to decline with only two rigs, then aren’t you going to have a less of a potential sale price on a multiple of EBITDA.

What I’d like to point out is we have seen extremes in the marketplace where companies sell at a multiple of 3 to 3.5 times EBITDA all the way up to establishing over $7 million per location of inventory. We feel like well over half of our bag will be our inventory of locations, not just selling on a multiple of EBITDA. So we are extremely encouraged by what the value of the company will be compared to where our stock value is today. And now I’ll open up the call to questions from our analysts.

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Q&A Session

Operator: [Operator Instructions]. Our first question comes from John White with ROTH MKM Capital.

John White: Good morning, gentlemen, and congratulations on having run such a good 2023. I was on another call with another Permian operator, and they cited decreased prices for tubulars, casing, and chemicals. I’m wondering if you’re seeing the same trend and what are you seeing in terms of rotary rig — rotary drilling rig rates, what direction are they in?

Jack Hightower: John, I’ll ask Mike, who oversees our operations on a daily basis, his got very current sense of the direction overall that’s taking place in the industry. So Michael will answer John’s question.

Michael Hollis: You bet. Thanks, John, for the question. And for everyone else on the call while we were during our prepared remarks, we got a note that some folks were having a hard time getting and downloading the presentation, so all of that has been resolved. So if you are having any issues getting the presentation that we were running through in the prepared remarks, please try and things will work now. But to answer your question, John, walk through it and hopefully you were able to see this slide, but we kind of walk through what prices have done over the last three years. And I think all of our cohorts and peers in the industry are telling you exactly what we’re seeing as well. Again, with HighPeak, we tried to make sure that we don’t lock in pricing for a long period of time in a very volatile kind of market.

So we were able to enjoy the decreases since the post COVID era, that roughly 25% reduction in overall costs. We’ve been able to enjoy that on the way down. Obviously, that’s continuing to bid out and stay on top of activity. And with the group that we have here at HighPeak, we’ve got a lot of experience and time in the industry to be able to garner what other companies may have to have a lot of scale and activity to get the pricing, we’re able to receive some of those pricings as well because we’ve been in the market and bringing so many rigs in the past here at HighPeak and other companies. So to answer your specific questions about rig rates, we definitely saw rig rates peaking six to nine months ago and you were seeing folks looking out upwards to kind of the $35,000 a day for rig rates for tier one super spec rigs.

What we’re seeing now, we never got to that point because we weren’t trying to lock in multiyear contracts. So we never approached much above $30,000 today you’re down closer to the $28,000, $27,000 range on an average for your higher spec rigs. There are some out a little cheaper, but again, we look holistically. We may not use the cheapest one piece. It’s how we put the whole pie together that allows us to generate the lowest dollar per foot in the public space today.

John White: Thanks very much. And another question. What level of crude oil price would you have to see? And how long would you have to see to decide to add a third rig?

Jack Hightower: Good question, John. Of course, price in and of itself is one part of the equation. Our return on investment is another bar in where the economy looks to be going. As we mentioned a $10 increase in oil gives us roughly $110 million plus of additional EBITDA, which goes directly to free cash flow. One thing I think’s important for our shareholders understand, though, with six rigs, we can be compounding production tremendously. And with three rigs, we start increasing production tremendous. So at the end of the day, the basic component is an increase in oil prices, and with an increase in oil prices, considering also our philosophy of maintaining prudence and discipline, we would start considering to increase our rig count. But it’s not a simple question to answer.

John White: Okay. The commodity markets are complicated. So I understand your guarded answer. I’ll pass it back to the operator.

Operator: Our next question comes from Nicholas Pope with Seaport Research.

Nicholas Pope: I was hoping you guys could talk a little bit about the cadence of two rigs compared to the one frac crew. How you all expect those wells to kinf of be — kind of fleshed out over the quarters of the year? And how you’re thinking about just that pace, the ongoing pace and kind of the wells that you’re coming in with — coming into the year with?

Jack Hightower: Yeah. Mike, why don’t you answer that question?

Michael Hollis: Absolutely. So Nick, yeah, of course, we’re getting fairly efficient and more efficient every kind of week month as we go with our completion crews. And at HighPeak, we do drill a lot of wells, a lot of lateral foot per rig. So as we sit today, we are able to complete with one of these kind of, again, Tier one frac crews, dual fuel, very efficient. We’re able to complete all of the wells behind kind of to call it 2, 2.5 rigs. So as we mentioned being a slightly front-half weighted on CapEx of B and C, what drives that is we’re able to have completed about a 2.5 rig cadence through the first half of the year and go to a two-rig cadence through the latter half of the year. So that that’s a slightly front end weighted.

So you can imagine toward the back half of the year, you’ll have a couple of a little few day gaps in between the pads. Now as far as the ratability, which means as we’re drilling these wells as soon as we move off of a pad, we move the frac crew in and complete. So the pad sizes we’re drilling in 2024 are very similar to the pad sizes we were drilling in ’23. Hence, ratability per rig will be about the same as well as the completions and turned in line.

Nicholas Pope: Got it. That’s helpful. And switching to the financial side of things. I was hoping you could talk a little bit about the decision to increase the dividend and how you weigh that cash going out the door for the dividend relative to the big term loan that you put in place in the summer. So kind of how you think about what could be paid off? What you’re allowed to to pay down on that new debt instrument? Obviously, it’s got a pretty big note with where interest rates are. So just kind of curious how you’re balancing those cash options kind of outside of drilling right now?

Jack Hightower: Good question, Nick. And our basic answer there is the dividend relative to our annualized basis of $25 million is pretty de minimus. It doesn’t really help us to do another $25 million on a $1 billion to pay down of the loan. But it gives us more value return for the shareholders. Our stock is depressed in our opinion. Hence, the reason we have a share buyback and why you see management in our last offering do a offering. So we’re going to continue that program. And as far as buying back stock, when we negotiated our home. We got permission to do all these things to increase our dividend to do a share buyback and to have that flexibility. And we do have restrictions in terms of pay down of the debt. We have an amortization in place, but we also have restrictions that limit our ability to pay down without any make-whole provision.

Operator: Our next question comes from Jeff Robertson with Waters Tower Research.

Jeff Robertson: Thanks. Good morning. Mike, can you talk a little bit about reserve bookings in the capital program in 2023 and what you anticipate in 2024 and the kind of capital that’s being spent on the program and how that compares to the last several years?

Michael Hollis: You bet, Jeff. Again, as we’ve slowed down activity somewhat, we will be drilling a few less wells, obviously somewhere in the kind of wells drilled in about 60 turn-in lines this year. So again, when you look at the well performance, what we’re drilling today compared to what we did in 2023, the well performance in ’23 was across broad spectrum of both blocks. So the wells that we’re drilling today mirror what we kind of did in 2023 ex the few efficiencies and things that we’re learning as we go along our way. So if you kind of take that forward into what our reserve booking will look like, you can kind of think of 2023 being an average of a four-rig program. So the growth that we saw in 2023, the adds, now that production roll-off was going to be less than the production that we’re going to make in 2024.

It’s going to be close. So I think roughly the same roll off with about half of the adds of reserves. And then, of course, we’re always very conservative on our PUD bookings. So don’t look for us to be a company that’s going to go out and do 60% 70% PUDs and only 30% proved. What we show is our proved reserves is closer to 40%, PUD more like 60% to 65% proved or PUD. So hopefully that gives you a pretty clear picture of what 2024 will look like.

Jeff Robertson: When you think of 2024 and the capital intensity of the asset base, is it fair to think that a two-rig program over time will decrease the natural decline rate in the existing proved reserve base and therefore maybe decrease the capital intensity? We’re trying to offset decline and maintain or grow production.

Michael Hollis: You bet, Jeff. It’s kind of a kind of a two sides to that equation. One side is obviously every well in the Permian Basin decline. So as you decline out over time, the decline rate reduces. So as the base production ages, the corporate decline will go down over time. And as we’ve reduced activity toward the second half of ’23 that will allow that base portion of the production to reduce its overall decline rate. So again, as you mentioned, it makes it easier to hold that production as well as to have a basis declining left that you can grow off of as you deploy capital. The other piece on the efficiency front for the capital efficiency kind of walk through that on slide 10, where we walk through where costs are today.

And as we’ve mentioned, we’re mainly focusing on co-developing the A and lower Spraberry. They are our two highest rate of return and capitally efficient zones, as well as the cost for services and tangibles are going down as well as the efficiency of the drilling and completion side going up over time. So yes, do we see 2024 from a capital dollar utilized to what we get out of it being much more efficient than where we’ve been in the past? Absolutely.

Jack Hightower: Will that start to show through in your — in the DD&A rate, Mike or Steve?

Michael Hollis: So DD&A rate — and let me give just a little bit of clarity about DD&A rate and for HighPeak versus peers. So again, almost all of the growth that we’ve had at high peak has been through the drill bit. So by nature alone, there you will have a higher DD&A rate. Typically, if you bought something you would classify some large amount of that price being lease hold that gets distributed across all of your PUDs as well as your PDP. We only do it through the drill bit. We take a lot of our leasing calls and divide that only by the proved reserves for those wells. We’ve also built out life of the field infrastructure, and that’s obviously very front end weighted to the life of the company. And most all of those calls are in now and again divided by just our proved reserves.

And then you even go to the BOE mix that HighPeak has, although it’s very, very valuable because it’s very oily and very little gas that’s got a very depressed pricing today, it’s fewer BOEs. So again, if we were producing at the same kind of mix and generating the same EBITDA as our peers and had an 86,000 BOE a day kind of number to point to the same EBITDA, that, again, just by itself would reduce our DD&A down into the $18 range. And then as we continue to infill and drill these wells, that leasehold as well as the infrastructure dollars that are already allocated in our DD&A numbers today will get diluted with reserves that had virtually none of those costs associated with it. So to your point, over time, as we continue to drill these wells our DD&A will continue to trend down and look more similar to what your other operators in the area are at today.

Operator: Thank you. This concludes today’s conference call and thank you for participating. You may now disconnect.