HighPeak Energy, Inc. (NASDAQ:HPK) Q3 2022 Earnings Call Transcript

HighPeak Energy, Inc. (NASDAQ:HPK) Q3 2022 Earnings Call Transcript November 15, 2022

HighPeak Energy, Inc. misses on earnings expectations. Reported EPS is $0.85 EPS, expectations were $0.89.

Operator: Thank you for standing by and welcome to the HighPeak Energy Third Quarter 2022 Earnings Conference Call. And now I would now like to introduce your host for today’s program, Mr. Steven Tholen, Chief Financial Officer. Please go ahead sir.

Steven Tholen: Thank you and good morning, everyone, and welcome to HighPeak Energy’s Third Quarter 2022 Conference Call. Representing HighPeak today are Chairman and CEO, Jack Hightower; President, Michael Hollis; Vice President of Business Development, Ryan Hightower; and I am Steven Tholen, the Chief Financial Officer. During today’s call, we will make reference to our November investor presentation and our third quarter 2022 earnings release, which can be found on HighPeak’s website at www.highpeakenergy.com. Today’s call participants may make certain forward-looking statements relating to the company’s financial condition, results of operations, expectations, plans, goals, assumptions and future performance. So please refer to the cautionary information regarding forward-looking statements and related risks in the company’s SEC filings, including the fact that actual results may differ materially from our expectations due to a variety of reasons, many of which are beyond our control.

We will also refer to certain non-GAAP financial measures on today’s call. So please see the reconciliations in the earnings release in our third quarter investor presentation. I will now turn the call over to our Chairman and CEO, Jack Hightower

Jack Hightower: Steve, thank you very much and welcome ladies and gentlemen. I’m going to start by saying basically that we’ve continued to grow the production and all aspects of the business. This has been a great quarter; what we’re most proud of is a 63% increase from second quarter average production to our fourth quarter to-date average rate of over 35,750 barrels of oil per day. No other company has been able to generate that kind of growth while maintaining a conservative balance sheet and staying below one turn of debt to EBITDA that’s in keeping with our plan. We’ve grown our acreage position. We’ve grown production. We’ve grown cash flow, and we continue to substantially add to prove reserves as we expand our development program across the entirety of our acreage bought in several different zones.

Our average 2022 well results are outperforming our prior year results, which is unlike lots of companies in the Midland basin. This speaks to the quality of our reservoirs and both flat top and signal peak and our technical teams continue to learn things as we progress across our development program. All this is despite the supply chain constraints, inflationary pressures that our industry as a whole has been facing over the past year. It’s both a tribute and a testament to our team, our asset base, our high liquids cut, and the performance of our wells and the reservoir that we’re drilling these wells too. We expect this growth to continue as we move forward. Another thing I’m extremely proud of is how HighPeak has navigated these obstacles and been able to deliver this level of consistent growth.

We are absolutely a differentiated growth story and we’ll continue to execute our business plan. Now if you will turn to slide 4 of the investor presentation I’ll give you additional details. Most of you are familiar with this slide. We keep it in context of looking at our acreage position expanding the fact that we have two identical big acreage blocks. Our sale volumes average 26,250 barrels a day for the third quarter, an increase of 19% compared to the second quarter but in looking at long term that’s a 220% increase year-over-year compared with the third quarter of 2021. Our current production rate has significantly increased since the end of the third quarter and is average 35,750 barrels a day in the fourth quarter, tremendous increase.

At the end of the third quarter, we had an additional 57 wells in various stages of drilling and completion which was placed on line will continue to support our current production growth trajectory. We’ve averaged over six rigs and three frac crews, as planned throughout the entirety of the quarter. And we did all this continuing to maintain our leading margins as our third quarter unhedged cash operating margin was $72.01 per barrel. We’ve continued to expand our acreage position also, which I’m really proud of. It now sits at over 105,000 net acres. This is a 68% increase compared to year in 2021. But almost 8000 acre increase since the last quarter. We have a high net working interest position across the block and we operate roughly 98% of our acreage, which allows us to control our own destiny.

And by that, anytime we want to drill a well, we can drill a well, we can do what we want to do on our acreage spot. It’s also worth noting that even factoring in our additional leases, we can hold this entire acreage position together with less than two rigs in our annual drilling program. So this is a long term position we have and we’re not under pressure to have to develop it when prices are down. We’ve also been busy in the capital markets recently. In a very short period of time, we raised a total of $435 million and as you all know, it’s a very challenging capital market environment. The financings include 85 million of equity, private placement, the majority of which came from management and our largest legacy investors. And I’m going to talk about that a little bit more in my closing remarks.

We increased our borrowing base from 400 million to 550 million with elected commitments of 525 during our annual fall redetermination. And that’s increasing. We also added new banks to the facility and brought in Wells Fargo as the new lead bank. I want to take this opportunity to thank for their support and leadership over the past few years as a former lead bank of our facility. And I’ll remind everyone, we started with the initial borrowing base of $40 million in size. And that’s now grown to 550 million in less than two years. And so we want to thank them also for their continued commitment in our facility going forward. We recently closed a private placement at 225 million senior unsecured notes, which we’re really proud of. We got good terms on that.

And we liked the people that we’re dealing with on our senior unsecured notes. There’s a lot of potential unpredictability in the global economy at the moment. There’s talks of recession on the horizon, their service costs inflation, supply chain bottlenecks, government regulation, and short term volatility and commodity prices. However, taking all these factors into account, we want to make sure the company is positioned to protect against any sustained market disruptions. We’re a company that is focused on responsible growth. And we continue to monitor the market as we progress with our development program. We’re very fortunate in that we have the flexibility to increase our decrease development activity, as merited by sustained changes in market conditions.

Now turning to slide 5, and you can see four different categories of differentiated growth and what’s happening to HighPeak today. We’re continuing to grow our production base and cash flow at an impressive rate. HighPeak is definitely a differentiated growth story. Our drilling program is operating on all cylinders. We’re creating significant shareholder value. That’s not reflected in our stock price right now. But we’re going to talk about that too. We’ve come a long way in a relatively short period of time. We’re substantially different company today than we were at the beginning of this year. If you take our fourth quarter production it equates to an estimated run rate of over $930 million. That’s over 70% increase compared to the second quarter.

We’re approaching a billion dollars in EBITDA run rate, and that in and of itself should be a major catalyst for our stock price. HighPeak provides great exposure to both growth and increases in oil price. For example, any $5 increase in oil equates to approximately 55 million increase in annual EBITDA and that’s not EBITDA on growing. That’s EBITDA with our production rate right now today. This should equate to roughly $2 plus per share increase in our stock price. Our successful drilling program continues to deliver high margin organic production, growth and a very tightly supplied global oil market. I’ll say again HighPeak is a differentiating growth story and is taking advantage of current market environment in order to create maximum value to our shareholders.

And then I’m going to turn the story over to Michael Hollis, our president, and he’s going to tell you about what’s going on with the growth of HighPeak and the operational aspects.

Michael Hollis: Thanks, Jack. Now turn into slide 6. HighPeak’s differentiated margins. I’ll stick to my theme that not all BOEs are created equal. Even as HighPeak has grown production 220% year-over-year our margins remain best in class. In the third quarter, we generated 36% more margin per BOE than our peer group. Our margin represents 84% of high peaks realize price per BOE are set a different way. Our margin per BOE is over 78% of the third quarter average NYMEX oil price. Where else could an investor get exposure to oil price, extreme growth and vastly differentiated margins? HighPeak is that trifecta. We’re positioned for continued margin expansion with our LOE reduction initiatives. For example, our removal of generators, electrifying our operations, the expanded use of recycling and company owned SWD systems.

HighPeak will also benefit from the dilution of fixed costs as our production continues to increase. Now turning to 7. LOE. Although our LOE was only down 1.5% quarter-over-quarter, our lease operating expense, excluding workovers, was down 12.5%. I’d like to provide a little more color or what makes up our LOE and how it’s trending down over time. Our third quarter was impacted by non reoccurring workover expenses associated with our acquired properties in bringing them up to HighPeak standards. The largest cost was a repair to one of the SWD. HighPeak’s workover experience typically runs less than $0.10 per BOE. And this quarter, we were at $0.93 per BOE. It’s normal when taking over operations and new properties to have a quarter or so of elevated workover expenses.

And it would be reasonable to expect that these have already began to normalize. So what will drive LOE in the future several factors leading to decreases in LOE again additional generator removal as we continue to electrify the full flattop field, including the acquired properties in Borden County. One of our gathers is ramping up a plant expansion this month, which will allow HighPeak to bring on additional sales volumes. Dilution of fixed cost is production continues to scale, further infrastructure build out in signal peak. Conversely, we’ve had the same inflationary LOE headwinds that the rest of our peers have had, including increased chemical costs, fuel cost, workover and labor cost. But with that said, we believe these inflationary headwinds are vastly overshadowed by our LOE reduction initiatives that we’re implementing currently.

HighPeak is one of the few companies that continue to drive lifting costs down and margins up. If you’ll turn to slide 8 now; total cash cost. As you can see, our total cash costs have continued to decrease quarter-over-quarter. As our cost saving initiatives have started to kick in, Q3 was down 8% quarter-over-quarter. In addition, we have tailwinds for further cost reductions on the horizon. As we discussed in the previous slide, LOE was affected in Q3 due to some non reoccurring workover expenses associated with our acquired properties. Large scale production growth, as evidenced buyer announced fourth quarter to-date volumes. And as you know, again, fixed costs continue to decrease as our production grows. All that said, our current costs compare very competitively with our peer group.

And yet, we still have a lot of room for further reductions. And this is a good spot to give a shout out to the operations team. This year, we brought on a lot of wells, a lot of new batteries, rolling production significantly, and integrated multiple acquisitions, and accomplishing all of this with LOE cash costs near the low end of the peer group and continuing to improve. This is a statement and a testament to the experience, grit and hard work of the HighPeak organizations. Now turning to slide 9, well performance. Something that’s been very somatic this quarter is well performance over time, and the makeup of that production from the completed stratigraphic benches. HighPeak continues to demonstrate consistent well results if we have expanded development across our entire 105,000 acres of both flattop and signal peak and develop a more diverse basket of formations.

From a completed lateral foot perspective, in 2022, we have averaged 40% of our lateral feet turned into line in both the Wolfcamp A lower Sprayberry respectively, and 20% in the Wolfcamp D as in David. Our 2022 vintage wells include larger pattern development, and a higher percentage of wells and signal peak. In the third quarter 22% of our lateral foot is turned in line was that signal D. We transitioned from a single parent well in the Wolfcamp A and flat top kind of development to full multi zone pad development in both of the geographic areas at HighPeak. Now shown on the graph on the right of the page, HighPeak’s 2022 Vintage wells are outperforming the previous two year results by roughly 10%. Make note that the chart on the right is normalized to 10,000 foot laterals.

And we averaged approximately 12,000 foot laterals across our blocks both flat top and signal peak which meaningfully increase our capital efficiency We have delivered these results despite co-developing larger pads and offsetting more existing PDP wells in 2022. Our reservoirs continue to perform to our expectations. And this is evidenced by our current gross oil production of roughly 50,000 barrels a day of oil, which is being produced by less than 120 PDP horizontal wells. The rock is good. With HighPeak’s low drilling complete costs are improving blended pad results, and massive inventory all equate to our wells absolutely being tier one inventory in anyone’s portfolio. Now turning to slide 10; operations. I’ll provide a brief operational update both in flat top and signal peak.

As Jack mentioned, we’ve added roughly 22,000 net acres continuous with flat top and another 20,000 net acres and signal peak since the beginning of the year, we were actively drilling on the acquired properties. And both areas compete for capital within our portfolio as evidenced on the prior slide. As we discussed our last call we commissioned our local HighPeak electrical substation in late May, and are in the process of converting our field operations for rental generators over to more cost efficient high line electrical power. With our expansion to the north and east at flat top, we added a few generators during the last quarter while we’re finishing the build out of our electrical system, we expect to have only a few generators left and flat top by the end of Q1, 2023 and hope to have all a signal peak in a similar situation by the second half of next year.

We anticipate plugging in our second rig to highlight power in mid December, and our third rig by Q2 of 2023. Significantly reducing our diesel needs. We are also fueling two of our rigs and one frac crew with dual fuel. By doing so it saves us capital and reduces our diesel usage and emissions. As we continue to reap the benefits of our local sand mine partnership we began servicing our second frac crew with local sand during October and expect to convert our third crew over to wet sand by year end, we have continued to convert more of our flat top oil production to pipeline sales. We currently have 75% of HighPeak’s total oil production gathered on pipe. Our goal is to have the remaining flat top volumes on heightened for year end. We also continue to further leverage our flat top water recycling system and are now servicing two crews with 100% recycled and non potable water again reducing cost and our environmental impact.

Down in signal peak, we continue our infrastructure build out which includes additional water recycling capability, as well as Highline power upgrades. For the remainder of the year, we plan to keep four rigs and two frack crews running at flattop and two rigs and one crew running at Signal peak. We obviously had a ton of work going on in the third quarter, we talked about the effect that non reoccurring workover expenses associated with a recent acquisitions had on our third quarter LOE, and along that same vein, third quarter CapEx came in elevated compared to our normal run rate as well. We spent $320 million. I’ll give you a little extra color to help tie this to our fourth quarter guided run rate. Due to some delays in completing the hackathon for well extended reach Wolfcamp D pad, which was originally planned to happen prior to closing the acquisition, then push those completions into the third quarter.

We picked up an additional frac crew to complete these wells and try to make up some of that lost ground. These completions as well as up infrastructure upgrades on the newly acquired acreage make up the roughly $30 million difference. And we feel that the fourth quarter budget, which we’ll discuss in a few slides will be more representative of our quarterly run rate going forward. Now turning to slide 11, ESG. ESG continues to be at the heart of every field and corporate level decision that we make. Our total recycled water volume continues to increase quarter-over-quarter we utilize 82% of recycled non potable water for third quarter simulation fluid needs and flat top And here are a few updates of our ESG emissions reductions for progress.

HighPeak supplanted the use of over 800,000 gallons of diesel in the third quarter. Having 75% of our company owned oil on pipe removed approximately 185 trucks per day from the road. We also have one rig on grid power. That’s a reduction of about 2500 gallons of diesel a day to raise or dual fuel 1500 gallons a day. One frac crew or dual fuel that equates to about 3000 gallons of diesel a day. Look, the Permian Basin is an extremely busy place to live and work and by using local wet sand, we eliminate an additional 110,000 road miles per well. That diminishes the safety exposure, emissions and total costs associated with completing these wells. That equates to 1.2 million gallons of diesel saved per year per crew that uses wet sand and this is based on a 95 mile reduction in distance from the sand mine to the well side.

And utilizing wet sand eliminates 5.5 million road miles per frac crew per year. Remember that our third frac crew is anticipated to start wet sand by year end. If we’re running three frac crews on wet sand we will have an annual run rate reduction of about 16 million road miles per year. Again reducing some of the congestion in our oil field in the Permian Basin. By using wet sand HighPeak also eliminated 25,000 metric tons of Co2 from being emitted into the atmosphere per year per crew. There’s no need to burn natural gas to dry this sand. It’s wet sand, as well as the reduced Co2 from the fear road models. When we have three crews running on wet sand our annual savings will approach 75,000 metric tons of CO2. On a final note high P currently has VR use installed on all the horizontal batteries of flattop and these batteries will all be converted to instrument air pneumatic controls by year end further reducing our methane emissions.

All of our ESG initiatives are both environmentally and fiscally rewarding to all of our stakeholders, the health and well being of our employee base in the community is priority one. With my comments now complete, I’ll turn the call back over to Jack.

Jack Hightower: Thanks, Mike. As you can see, as shareholders, our people have been very, very busy out in the field and growing the company in a responsible way. And I’m going to talk a little bit more about that. But literally, if you had an opportunity to visit our location, it’s almost developing a city out there with all the production with the water handling and with all the facilities were put in place. This is a big oil field and we feel like we have almost a billion barrels of oil to recover net to eccentrics. So we’re very excited about what we have here. Now turning to the slide on page 12; the capitalization and fourth quarter guidance. Our three recent financings have reinforced our balance sheet and considerably enhanced our liquidity by over 400%.

We were able to accomplish all three in a very challenging capital market and that speaks to the quality of our asset base and the support of our lenders. Our improved liquidity gives us plenty of capital to continue our current development program. We’ll continue to monitor the market for volatility and commodity process, service costs, and relative to our philosophy and the flexibility to increase or decrease our drilling program as merited. Our philosophy is still keeping net debt to EBITDA less than one time, taking our current EBITDA run rate of over 900 million. That puts us at a much lower ratio than what’s shown on the slide. It’s actually at about a six times multiple. As we looked at in the year, we estimate average of 35,500 barrels up to 38,500 barrels a day for the fourth quarter, we still have lumpiness in our production.

I’ve always said that growth and production with an oil company is plateau growth. You stabilize for a quarter or two or maybe go down a little bit. And then all of a sudden you have big growth like we had here. Our fourth quarter capital budget is anticipated to range between 295 million and 295 million. This equates to rig costs run rate of between 190 million and 200 million per year, which compared to our peers is much cheaper. But our team drills more footage with our rigs compared to our peers. We’re more efficient, and we’re faster. So we’re getting more for less price. Overall, our program is working as expected as evidenced by our track record of consistent production and cash flow growth, improved average well performance, all while maintaining a strong and simple balance sheet.

In closing, I’m going to spend a little bit of time basically saying that we continue to execute our responsible growth plan. We’ve expanded our drilling program across our entire block in every direction and into multiple formations. We are delineating significant proved reserves, and a long inventory runway which has significantly increased the fundamental value of our asset base. We continue to improve on all aspects of our business, especially on the technical side, as evidenced by our 2022 average well results outperforming prior years wells. To date, we’ve increased our production and cash flow at a rate rarely seen in this industry. Back I’ve never seen this kind of growth in many, many years, in a 52 year career. I’m extremely proud of the HighPeak team.

It’s truly a testament to our entire employee base, that we’ve been able to achieve these results in spite of the supply chain constraints, disruptions delays, inflationary pressures faced by our industry throughout the past year. We’re able to do all these things while maintaining a strong healthy balance sheet during a very volatile and challenging capital market environment. Our extraordinary cash margin driven by our high oil cut, low cost structure, strong well performance was 36% better than our third quarter pure average. And that allows us to generate excess cash flow, as Mike mentioned, barrels of oil are not considered the same. It’s a matter of how much dollars when you turn that barrel into dollars and cents. And we’re doing that better than anybody in our area in our peers.

We’re on the cusp of generating an annual EBITDA run rate of over a billion dollars a year. And we’ve got line of sight to reaching cash flow neutrality, and then transitioning to a period of significant positive free cash flow, while maintaining our impressive production growth. Everything I’ve covered during these closing remarks, indicates a bright future ahead for HighPeak. And in my opinion, it’s only a matter of time, before the broader market realizes that we definitely have a dislocation in our stock price that is currently trading relative to what the intrinsic value is of our asset base. Two things that I’m asked frequently is what do you think your company’s worth? Well, one of the main points of that is why did $85 million of our basic investors and management put in $85 million recently, at a price just a few dollars below where we are today?

Well, we did that because we think our value is very much higher than where it is now. You can talk about value. You can talk about multiple the cash flow. If you have a billion dollars a year right now today, then you could say, well, we ought to trade at least at a four to five times multiple. And then you have value for your acreage position, the number of locations you have. And what if somebody willing to pay for that upside. We’re not a comparative analysis to other deals in the market, small acreage positions coming out of private equity. This is a billion barrel oil field. This is something totally unique and different than what our peers have. Historically, an asset base like this would trade I averaged almost an eight times multiple in my last public company.

And yet we’re trading less than the multiple of our peers and growing production 220% in a year-over-year basis, that means we are fundamentally undervalued. If he said that we were at a five times billion dollar multiple not looking forward, but today, Where should our stock be? Two people, John Jim Cramer, just Friday, have come out with recommendations $50 with John, and Cramer just says, Hey, if you want to have exposure to a big increase in oil prices, and be bullish on oil, then HighPeak is the company of choice to buy. I believe that, our multiple is not where it should be, we’re not getting value for our acreage position even the last transaction in the marketplace was 1,300,000 per location, our locations are much more commercial, much more valuable.

We think that well over 1000 locations should be somewhere in a $1.5 million to $2 million on top of whatever our multiple is. So I conform with that minimum $50 a share and that’s going to be increasing over the course of the next 12 months. The other thing that I look at there is people ask me, well, why don’t you use your currency to go do a transaction? I can’t use my currency. I think our analysts would go absolutely crazy if they’re saying I’m worth $50 a share. And I use my currency down here at $23 a share. And I’m sure not going to go lever myself too high to buy something else. But there are other opportunities in the area as our stock starts to perform now with the success that we’re having. Then the other question is, well, where do you think prices are going to go?

I’ve talked about this before, but basically speaking, we are starting to approach a very, very delicate situation in terms of demand, irrespective of recession. If we hadn’t been having available all production coming out of the strategic reserve for the last six months, we would have been having even a larger decline in storage. And today that is what is actually going to start happening. We are going to have enough demand that we are starting to approach unprecedented lows in storage. And this is going to result in a much higher increase in oil and gas prices going forward. So in order to have our quality, our quantity of life moving forward, we’re going to have to increase production. And that’s going to take a lot of capital, or we’re going to have shortages.

And that’s what we’re predicting. Therefore, over the course of the next 12 months, we’re going to predict much higher oil and gas prices. So going forward, we’re very excited about HighPeak, very excited about our future, and about what we’ve been accomplishing. And more excited than anything about the different zones and potential upside that we have in our reservoirs. So I’ll now open the call up to our analysts for questions. Thank you.

Q&A Session

Operator: Certainly. And our first question comes from the line of Jeffrey Robertson from Water Tower Research. Your question, please.

Jeffrey Robertson: Thank you. Good morning. Mike or Jack can you talk a little bit more about the performance improvement in the 2022 drilling program and since you mentioned you’ve moved to full pad development in flat top and signal peak, does it suggest that developing these wells on full pads and drilling out all the locations, ultimately, is a better way to develop these reservoirs than having drilled ones and twos over the last couple of years?

Jack Hightower: You bet Jeff. And obviously, early in the development of an asset do you tend to delineate and you do small pads, singles, doubles. And again, as you’ve heard many of our peers talk over the last couple of weeks. formations in a strength column tend to talk laterally as well as vertically. So we co-develop the Wolfcamp A in the lower Sprayberry, both in flat top and signal peak, we co-develop those together. It’s absolutely the right way to sequence that development. The Wolfcamp B in some of the other zones are taking our stratigraphically. So distance from those zones, and we can develop them independently. But as the locations or the formations are closer, yes, we co-developed those. And you made a very good point, we are now doing larger pads developing offset current PDP productions.

So very early in the life of this asset, we had single wells, sometimes in just a single zone, which typically historically would be the best result that you would get. Over time just like every other aspect of the oil industry, we continue to learn, tweak and change the recipes landing for, landing points, sequencing of fracing different zones. So over time, we’re learning just as the whole industry is getting better each day. So I think you see that there’s other than co-developing and doing larger pads, the reservoir is the same, the techniques are slightly different today. But the results are continuing to improve. So again, with the massive inventory that Jack mentioned, the well over 1000 locations, and we can go and develop this way and have these kind of results going forward.

We absolutely have a machine that can efficiently grow production and generate a ton of free cash in the future.

Jeffrey Robertson: Maybe a question on the capital program, I think Jackie mentioned that one rig costs roughly $190 million to $200 million. Is that net to HighPeak’s interest.

Jack Hightower: Yes, as net HighPeak centers. I think one of the other presentations that recently saw amongst our competitive peers is about 250 million a rig is their estimate. But we are drilling, the longer laterals on average. We’re drilling our wells faster. So one rig at 190 million to 200 million for us is exposing us to more lateral accreative production. And we’re drilling the wells faster than our peers. So then 20% less cost compared to our peers doing it faster and covering more lateral fee is very economically sound for HighPeak.

Jeffrey Robertson: If you look out into 2023, can you give any numbers around what you think the average lateral of feet and might be over the program? It really the question is, will the 2023 program for dollar spent expose the company to more feet of reservoir than what you’ve done in ’22?

Jack Hightower: Well, as I mentioned, we’re going a little bit faster, and we’re growing a little further laterals, but we’ve averaged over 115 and ’22 for lateral flow, 11,500 feet. And then in 2023, I don’t want to give any guidance yet to 2023. But I think in keeping with where we were the last quarter and is a good round number to think about.

Jeffrey Robertson: Okay. And just a question in operating costs. Mike, you talked about the onetime workover expenses as signal peak. As you just move more into full development there. Are there any initiatives or any significant initiatives that HighPeak has that you can talk about in ’23 like what you did and flat top this year with the electrification and improved and enhanced saltwater disposal which will continue to drive down, LOE in that area.

Jack Hightower: You bet Jeff, very similar to flat top. We do not need the electrification of grade. We’ve got plenty of power in the area, we will run some additional lines to remove generators and do those things that just kind of blocking and tackling normal things. The biggest upgrade that’s happening this year into next year is the SWD system and recycling system. So much like flattop we will have all of our production corridors and batteries tied together to where we can efficiently gather the produce fluid and recycle it and return it back to frac jobs.

Jeffrey Robertson: Okay, thank you.

Jack Hightower: You bet.

Operator: Thank you. One moment for our next question. And our next question comes from the line of Nicholas Pope, Seaport Research. Your question, please.

Nicholas Pope: Good morning, everyone.

Jack Hightower: Good morning.

Steven Tholen: Morning.

Nicholas Pope: Hope you guys could talk a little bit kind of further on that CapEx number. Could you talk about I guess whatever you’re comfortable with on well costs, like what? I guess what that progression has been kind of through the year where we’re at right now, either on $1 per foot cost per well, just to kind of understand kind of the progression with inflation and everything else we’ve seen this year.

Jack Hightower: You bet, Nick. Look in general, if you said today, what’s your blended average well cost is it’s roughly $7 million a well. Now obviously, lower Sprayberry Wolf A wells up in flattop are a lot cheaper than the signal peak Wolfcamp D well, from a CapEx standpoint. But that blended number of you a good idea. Now, to answer the question a little differently, if you look from the beginning of the year to now and had zero ability to arrest some of the inflationary pressures, you would have been somewhere in the 25% increase, the 30% increase in well costs. Now, during that period of time, and we’ve utilized wet sand, we’ve gone to electrifying rigs. Of course, anywhere we can use dual fuel, we’re doing that, utilizing more of our home produced fluid to stimulate the wells.

All of these have helped us keep our inflationary costs down into the kind of 15% range. We’ve got more of these initiatives that as we mentioned earlier, kind of come into fruition between now and Q1 of next year, which will help reduce the inflationary pain that we think may be coming in 2023. You’ve heard a lot of our peers kind of forecast in the ’23 that there’s probably a 10% to 15% increase coming. Again, no one has that clear crystal ball, but I think that’s probably a good range to work from. So again, it’s not just that you have those inflationary pressures coming more importantly, it’s what can you as an organization, do to help combat that either through efficiencies, optimization, and some of these initiatives we’ve talked about.

Nicholas Pope: Got it. That’s very helpful. And the other. The other thing, I was hoping you guys could talk a little bit about just the production progression through the year as well? I think in the second quarter, you all talked about the pro forma production rate, including hackathon. And it looked very kind of flattish to where third quarter rate was. So it’s kind of hoping maybe you could talk a little bit about maybe what slowed that down from maybe where expectations were. I know, there’s been issues with kind of simultaneous frac operations. And I’m just trying to kind of fill the wedges there and kind of order for production.

Steven Tholen: You bet. Kind of multifaceted question there. I’ll, I’ll take it in different stages. But early on, if you go back to kind of our second quarter, we talked about a delay in bringing in a frac crew and a rig, kind of right at the closing of the acquisition. So, you know, again, that reverberates through the production profile. Because again, that kind of two month period on the frac crew just kind of stack some things up, we tried to make a little, a little of that up along the way. But again, that was a pretty big hole to try to get out of. In recent talks we’ve kind of walk folks through when you’re, you’re doing these large pads inside. And next to producing PDP wells, you do get some lumpiness, as Jack mentioned, very early on as your production bases small, you’d saw kind of what we had in our early time production growth, where you would actually see kind of a salty pattern.

And as you would go water out and impact some other wells. Early on, we had some quarters where the production was actually a little less than the previous. Well, as we mentioned, a quarter or so ago, those days are kind of behind us now. So as we the production base is large enough so that as we have these undulating patterns coming on and watering out here, and there, what you’ll see is on the salty pattern, the kind of bottom of the salt tubes, will now be a couple of 1000 BOE a day kind of growth. And then on the peak of those sawtooth patterns, you’ll see significant growth, 8,000 to 10,000 BOE a quarter, much like what you saw, with our quarter to date production in the fourth quarter. So again, these are very normal production patterns.

It’s just again, when you started with a pretty small base, it exacerbated that six, eight months ago. So going forward, you’re going to see a more normal growth up into the right. Again, it will undulate, but it will be always up into the right.

Jack Hightower: Yes, Nick, I would add a little bit to that in the context of when you go to pad multi well pad development, you automatically take more time, if you have any problem at all with frac, your frac, multiple wells on the pad, you’re going to have some delays. And timing is really the critical thing. It wasn’t a function of reservoir. It was a function of just timing and getting to our wells, getting to our completion, as Mike talked about delays, those delays are compounded when you’re doing multipad development, even though that development is proper for economies of scale, it does sometimes delay getting the production online until it comes in and stabilize patterns where you’re going up into the right and then all of a sudden, you have a big growth, like Mike talked about in terms of the point of the assault.

Nicholas Pope: I appreciate that Jack and Mike as well. I’ll hop off. Thank you for the time.

Jack Hightower: Thank you.

Operator: Thank you. One moment for our next question. And our next question is a follow up question from the line of Jeffrey Robertson from Water Tower Research. Question please. Thank you.

Jeffrey Robertson: Question for Jack or Steve on the balance sheet does the $225 million private placement that was completed a few weeks ago. I think on slide 12, you have 400 million in liquidity pro forma for that, does that give you the liquidity cushion you’re comfortable with as you think about where EBIT does is headed in 2023 and where inflation and prices might be?

Jack Hightower: Yes. This is Steve. And yes, we believe that was the completion of the $225 million of notes that we have have sufficient liquidity to execute our development drilling program. As Jack mentioned earlier, we have a line of sight and are getting close to cash flow neutrality. Our current run rate, in terms of is about a billion dollars based on our production quarter to-date so far, and so, yes, we do anticipate that that will be sufficient liquidity for us.

Jeffrey Robertson: And then one question, Steve, on all price realizations, you all have HighPeak averaged over WTI for at least the index I’d see for the first three quarters of this year and averaged above WTI last year is can you talk a little bit about the company’s oil price differentials and realizations where they are today? And what’s in place and where they might be in ’23?

Steven Tholen: I’ll take that one Jess. Yes so we’re hyping since today, nothing in 2023 will be any different than what we have here today, and 22. So going forward, that would be a good way to look at our realized price. Obviously, location of our field is very advantageous, when you look at your marketing and gathering pieces that go into the price you get through your product as well as your margins. Obviously, our two blocks sit right on either side of a local refinery, the delich, refinery and big spring. So when we look at our GP and T costs compared to our peers, we’re 30% of what our peers would typically have to have to pay to get their product to market and market that product. So we are unique in that aspects. We do get the ability to buy our barrel back.

Obviously, today. We’re utilizing middling pricing, which is at a premium. If it stays that way we’ll continue to do that in the future. If that changes, we have the flexibility to make a change to get the best realized price for it.

Jeffrey Robertson: Thank you.

Jack Hightower: You bet.

Operator: Thank you. This concludes the question and answer session as well as today’s program. Thank you ladies and gentlemen for your participation. You may now disconnect. Good day.