Thank you for standing by, and welcome to the First Quarter 2022 HighPeak Energy Conference Call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question-and-answer session. [Operator Instructions] As a reminder, today’s program may be recorded. And now, I’d like to introduce you host for today’s program, Mr. Steven Tholen, Chief Financial Officer. Please go ahead, sir.

Thank you and good morning, everyone, and welcome to HighPeak Energy’s first quarter 2022 conference call. Representing HighPeak today are Chairman and CEO, Jack Hightower; President, Michael Hollis; Vice President of Business Development, Ryan Hightower; and I’m Steven Tholen, the Chief Financial Officer. During today’s call, we will reference to our May Investor Presentation, our first quarter 2022 earnings release, and Form 10-Q, which can be found on HighPeak’s website. Today’s call participants may make certain forward-looking statements relating to the company’s financial condition, results of operations, expectations, plans, goals, assumptions, and future performance. So please refer to the cautionary information regarding forward-looking statements and related risks in the company’s SEC filings, including the fact that actual results may differ materially from our expectations due to a variety of reasons, many of which are beyond our control. We will also refer to certain non-GAAP financial measures on today’s call. So please see the reconciliations in the earnings release, which was issued Monday afternoon. Our prepared remarks will begin on slide four of our May Investor Presentation. I will now turn the call over to our Chairman and CEO, Jack Hightower.

Thank you, Steven, and good morning to everyone, our investors and stakeholders, as well as analysts and other interested parties. This is, by far, the most exciting presentation that we've given to-date in HighPeak. We are pleased to announce and update our shareholders on the progress of the company and provide additional details on our recently announced Hannathon properties, as well as other acquisitions that we have consolidated over the last quarter. We are substantially a different company today compared to a year ago and this will be obvious from the information we're going to discuss throughout the presentation. We're going to try to spend as much time as we can in updating you on current prices, production rates. We're approaching cash flow neutrality and expect to transition to positive free cash flow in the second half of this year [ph]. And this is all while maintaining our trajectory on production and current growth. If prices continue at these levels during 2023, we expect to be one of the few, if not the only US company which is substantially increasing production and generating significant free cash flow. As I've stated before, HighPeak is definitely a differentiated growth story. If you'll turn to slide four in the presentation, there's many interesting things. And I want to refer everybody [ph] to the press release recently, because our stock’s down right now quite a bit. And this is a super buying opportunity. And in fact, when you look at the press release, it's easy to say, well, if our production went from 15,000 barrels in the first quarter to 12,000 barrels and now HighPeak legacy is at 25,000 barrels with Hannathon we're over 28,000 barrels -- 30,000 barrels a day. Well, you might say, what about missing your first quarter production? We've added…

You bet. Thanks, Jack. You know, if you now to slide 8. Q1 2022 margins. Everybody has heard me say this before, not all BOEs are created equal. We've got a much different commodity mix than most of our peers in the Midland Basin. The slide 8 highlights HighPeak’s continued unhedged peer-leading margins. Our Q1 margins were 21% above our closest peer and 33% higher than the peer average. We are also positioned for further margin expansion with our LOE reduction initiatives and the dilution of fixed cost as our production continues to increase. Our adjusted pro forma EBITDA margin of $73 per BOE based on our Q1 actual margin plus estimated uplift from near-term power projects and G&A per BOE reduction is 39% higher compared to our Q1 2022 year average. Further on average peer equivalent margin basis, HighPeak’s current pro forma production is equivalent to 39,000 BOE per day. I’d say in another way, it would take the peers production of 39,000 BOEs per day to equal HighPeak’s profit at our current pro forma production rate of over 28,000 BOE per day. Turning now to slide 9, Flat Top Activity. We faced turns in the past about our acreage potential as we move to the east and Flat Top. All of our modeling had suggested that it would be similar across our entire block. But I'm pleased to share some well results as we now have oil in the stock tank. As shown in the red outline on the east of the map, we have several wells that have IP-ed above 1,000 barrels of oil per day, and some that have reached up to 1,200 barrels of oil per day plus associated gas. Similarly, on the far north side of the flat top, we again have wells that…

Thanks Mike. Everybody turn to slide 15. It will give you a sense, again, in terms of what we talked about. I want to emphasize our 2022 guidance that we're right on track for, our 2023 guidance to we're right on track for, showing us to exit at an average midpoint of 80,000 barrels a day. Think about going basically from 12,000 barrels a day at the end of the first quarter to end of next year at 80,000 barrels a day, still maintaining the capital expenditure budget, because of the preplanning that we did that so many companies didn't see coming, having total cash costs of very low finding and development cost and being able to divide our activities between two great areas that are showing complete performance success that we're tremendously excited about, and doing it with realized pricing that is among the highest in the industry. So, when you look at that and you see that growth, and that's what I want everybody to focus on is looking at our growth. And now turning to slide 16. There is no question that our growth story is going to continue on, and it's a responsible story. We are now approaching complete, not any overspend, but complete success within our own budget. We have definitely operational excellence, thanks to Mike and his team. We have a strong balance sheet, even post closing this. In terms of borrowing money and utilizing our reserve borrowing base, we are going to be in great shape from a debt to equity. We've always said, we're going to maintain one year debt to equity. Our goal is to maintain our peer-leading margins also. And actually, with the implementation of the things that Mike talked about, our margins are actually going up, instead of going down, like most companies are. We believe in basically under-promise and over-perform. We are not running our company quarter-to-quarter, which you could look at and say, well, maybe we didn't hit our numbers. Well, those weren't our numbers. Our guidance is based on a yearly guidance basis, and not quarter-to-quarter. Our goal is to making money and making sure that we do things responsibly and take the necessary time to put our wells on to produce our wells properly to maximize the profit for everybody. Right now, we're running our company on the basis of all 10 fingers. That includes a great proactive drilling program as well as the three acquisitions we made, making sure that when we do consolidation opportunities, we do it on an accretive basis to make the shareholders' money. We're going to continue doing that. And we -- this is truly the best quarter that we've ever had relative to where we are today versus where we were at the end of the year and that is going to continue forward. So, we're excited about it and now open up the presentation to any questions that anybody might have.

Certainly. [Operator Instructions] Our first question comes from the line of John White from ROTH Capital. Your question please.

Good morning guys and I -- Jack, I appreciate you spending a lot of time on my guidance and where production is -- the wells being knocked off line by offset fracs. It doesn't concern me. People that follow the industry know that happens to everybody from time-to-time. I'm glad to see slide four has been updated to include the new acreage to the north of flat top and you're not going to tie hold me like you did on the last call. So, you've expanded flat top mainly to the north and you've expanded Signal Peak mainly with the Hannathon mainly to the South and the West. Is that correct?

Yes, that's correct.

And then on slide nine at flat top, the circles are indicating activity going forward is going to be focused on the northwest part of the block and on the southeast part of the block. Is that correct?

Yes. We'll have other activity all the way across the block in terms of drilling and development, but we were just showing that since it was new to the northwest -- and since there have been questions regarding moving east to the south, we wanted to demonstrate what the success has been in our northern area in terms of why we made that acquisition and the results of the wells that are being drilled there and then moving down to the Southeast to show that we now have wells in the 1,000 and 1,200 barrel a day range and even two more zones down there that are coming in. So, it's just showing that the entire acreage block is now perspective and we will be in process mode to start developing the whole block.

Okay. Thanks for that clarification and I'll pass it along and get back in the queue.

Thanks John.

Thank you. Our next question comes from the line of Nicholas Pope from Seaport Research. Your question please.

Good morning everyone.

Good morning.

Hey, I was hoping you guys could talk a little bit on Signal Peak. You got a bunch of new data here. It looks like the Wolfcamp D, I mean, kind of confirming what you all thought about being fairly extensive across that acreage position. I guess what did you learn with the new the Wolfcamp A and the Lower Spraberry in the Signal Peak and kind of like how extensive you think the potential could be on the asset, or has it changed, or is it kind of just kind of confirming what you all have been thinking about that -- those different formations?

You bet, Nick. No, you're exactly right. It confirmed our initial estimate that the Wolfcamp A and Lower Spraberry, we're going to be very productive and perspective on our Signal Peak acreage. Now obviously, we kind of step out, if you look at the Wolfcamp A, the closest Wolfcamp A production is over to the West of the Hannathon block. So again, part of the strategy of drilling the Wolfcamp A here and 1,000 barrel a day production and associated gas that we have today helps prove up from the western side of Hannathon at least over to where we have 1,000 barrel a day well. And we expect it to move over into the middle part or more of our legacy Signal Peak block. So again, it was just more of a confirmatory delineation well. The Lower Spraberry, there was a little bit of well control in the area a little closer. But again, met and exceeded our expectation. The Wolfcamp D, as you mentioned, it's its perspective all the way from the West to the East, North and to the South of our acreage block. So again, we're very excited about the runway of those three zones as well as Hannathon has done some delineation in the Wolfcamp B, as well. I don't know if you have anything else you want to add, Jack?

No. The only thing I would add, Nick, in addition is we do a lot of technical work that even the majors don't do. And we -- we've done a lot of additional petrophysical analysis, core analysis, sidewall cores all the way across and analyzing this area. And we've talked about the hurdle of zones, so I'm not going to add too much there, but we think we understand it much better now, as a result of this drilling and further evaluation. And that we perhaps will have some really exciting things happening in that particular formation also as we go forward. But undoubtedly, our goal was to delineate towards the all the way across, make sure it's commercial and add those roughly 500 -- 400 to 500 locations to our inventory. And you've seen the economics of it. So we're really excited about it.

Yeah. That's great. And as you kind of think about the hierarchy of like wells both comparing, what's the Flat Top and kind of what -- where we are at kind of in -- kind of delineating Signal Peak. I guess, has anything changed in terms of like where you think priorities are or like what the economics look like? And how do the economics, I guess, compare in Signal Peak with what you've seen Wolfcamp D versus kind of the Lower Spraberry and …

Yeah. You have the economics in the presentation on Wolf D and a great comparison is to go to the appendix, and in the appendix, you'll see the economics on the Wolf A and overall, which includes -- it's basically the same in the Flat Top area and in the Signal Peak area in terms of those economics. They're so close. There's no doubt that it's a little bit better in the Wolf A, but they're both very competitive. Our breakeven cost is 29 on the Wolf A, it's 34 in the Wolf D, but our returns at $100 oil are in excess of 200% in both areas. So, it's very comparable. It's very good and anybody would put these in the top tier of their investment profile on any acreage, anybody has in the Delaware or in the Midland Basin.

Awesome. That's great. I appreciate the time, everyone.

Good. Thank you, Nick.

Thank you. Our next question comes from the line of Jeff Robertson from Water Tower Research. Your question, please.

Good morning. As you all look at flat top, you -- Mike or Jack, you have a lot of densely spaced wells on the western side of your block where you initially moved into development mode. As you move away from there and go out, either to the east or north into Alamo, were you -- is it fair to assume you will not have the same type of impact from having to curtail -- offset production as you bring new wells online?

Yes, Jeff, as you mentioned, we had to go in and infill some of our kind of delineation wells, kind of had some book and drilling that had production on either side. So, yes, the amount of wells that we had to shut in for protection, as well as some water out effect, was a little higher over the last couple of quarters than what you'll see going forward. But also, when you go to manufacturing mode, you tend to drill more wells off of a pad. And, again, you're only going to be on one side of a set of wells. So the amount of disruption to that production will become smaller over time overall, as well as the growth profile that we have. The base is getting large enough now, as well as the growth is accelerating. So to have couple of hundred barrels a day per well off for four or five wells on and off throughout a quarter, will become less and less apparent in the growth profile as we go forward. Just know, every company everywhere in the basin turns wells off and sees water-out effect. It's just how big of an effect do you see in the daily production, it will become less and less of a percentage for us going forward.

And, Mike, have those wells generally come back -- as you've returned wells to production, have they generally returned to their type curve profile?

Absolutely, between shutting wells in for fracking, shutting wells in for weather events, COVID, a number of events that happen, these wells get turned on and -- or turned off and return to production many times through their lifetime. We've got wells almost 3.5 years old that have went through those cycles, have had wells fracked on either side of them at different times. And through every one of those events, just like they do in the center part of the basin, and the rest of the Permian in general, the wells come back on. You get a little flush production, and then they come right back on to their type curve.

A question on Signal Peak, I think when you all announced the Hannathon deal, you referenced that they had a 3D survey. I think you all have a 3D survey of your side of the acreage. Can you merge those two surveys together and maybe use them to high-grade landing zones within the Wolfcamp D

Absolutely. So, of course, once we close the transaction, we'll be able to integrate the 3D seismic that Hannathon has and be able to utilize it in the same kind of 3D earth modeling and trajectory pathways that we're utilizing now in all of our legacy assets.

If I remember right, the Wolfcamp D is a pretty thick formation in Signal peak. Is that -- am I remembering that correctly?

You are remembering that correctly. Yes, sir. It's pretty thick, roughly 450-foot thick. So again, a lot of resource in place.

Are you testing different landing zones?

We've got a -- we've kind of got our preferred landing zone as we sit today. And again, just being pragmatic kind of scientist we -- and engineers, we like to -- we like to do what works. Now does that leave some room in the future for Chevron into the different landing zones within the Wolfcamp D, it does, but our preferred development plan right now is to stick with what we know performs and produces these kind of results.

And last…

One thing I would add, Nick, to that and what Mike is talking about, when you look at this area from a macro perspective, and I've been doing this now for 52 years. And one thing Mike says is oil in the stock take. This area now, from a process perspective, looks to have recoverable oil from these zones, these big zones, the oil in place and the ability to recover this could be approaching now a net to high peak of $1.5 billion barrels plus of oil. It's a tremendous reservoir, tremendous opportunity and like every reservoir, in fact, our team managed over 27% of the tertiary recovery floods in the Lower 48, which are the biggest oil fields in the Lower 48 in the United States. And in every case, over time, we will improve the recoveries. And we don't expect that to be different here we're getting better and better of picking the landing zone and figuring out how to complete the wells and how to maximize the recovery. So the fact that we have such a tremendous amount of oil in place it's going to get better and better as time goes on.

Thanks, Jack. One last question on infrastructure. You highlighted the water disposal system that Hannathon has and that you all have existing on your legacy Signal Peak acreage. Mike, can you talk about how you can leverage this bigger acreage block into cost saving measures, whether it's discussions with crew gatherers or as you start to think about a manufacturing mode here? And are there power solutions that you can provide across a bigger acreage that will deliver on the operational cost synergies you all cited when you announced the deal?

You bet. If you look at what we did up in Flat Top and how we've integrated everything together, which again, works on that efficiency equation from cost on OpEx, CapEx as well as realized price. Having a big consolidated block like we now have in our Signal Peak area once pro forma Hannathon, it definitely gives you a better ability to work with partners on the gathering side. the existing water infrastructure that Hannathon has. We are currently connecting with Hannathon and sending water to some of their SWDs. So again, there's some synergies day one, they will be able to accelerate. Having more production from the wells that we have across this entire block allows us to have a higher recycle percentage from stimulation fluid, both from an ESG standpoint as well as from a cost savings standpoint. So all in all, whether it's oil, gas, water, power, having a big consolidated block absolutely helps. It's one corridor across all of it that allows you to efficiently develop your wells and produce your product.

Great. Thank you very much.

Thank you. Our next question comes from the line of John White from ROTH Capital. Your question please.

Yeah. Thanks again. On Slide 10 and referencing the previous discussion, I think, Jack, you mentioned that you think the economics for the Wolfcamp A and the Wolfcamp B are going to be neck and neck?

Absolutely.

That sounds good. Congratulations on getting that Powell well out there to the Far East, that's a real nice control point for your Wolfcamp B on Signal Peak. And Mike, congratulations on getting your substation commissioned. Jack, you mentioned the formation you called it Hutto. Is there a more conventional name for that?

Well, it's a part of the Wolfcamp C zone. It's a specific zone in that. And the reason it's called Hutto is there is a vertical field in the northwest part of our block that produced approximately 15 million barrels out of that zone. And so we're just moving across, just like we did on the Wolfcamp D, it wasn't like we moved out and drilled a wildcat well, we had a tremendous amount of well control. We had a lot of data. We had samples in the area. We had core analysis, the same with the Hutto. There's enough vertical production in the area we pretty well know what that zone is going to -- how much oil is in place and is simply getting in the right location and landing the well properly to get the oil of the ground.

Again, some real nice control points there, and thanks for that. Mike, did you mention dry sand and wet sand?

Yes.

What's…

Well, it's typically the sand that we use in our completion operations is dry. It would look like sand from a sand dune, but typically, how you recover that as it's mined from the surface mine and then it's cleaned and it's wet and then they typically have to use natural gas burners to drive the sand, which makes it easier to transport and to all float at the frac job. Utilizing wet sand, you take a step out of that and a lot of BTUs have to be burned and utilized to drive that sand. And the industry has gotten -- the technology has gotten a lot better lately to where wet sand utilization no longer causes the usual headaches of having kind of clumpy wet sand. They've got all that figured out and are able to off-loaded for the frac jobs very efficiently. So that's really the difference.

Okay. I appreciate that explanation. And I'll pass it on.

Hey, thank you.

Thank you. Our next question comes from the line of Mark [ph] from Wexford [ph]. Your question, please.

Hi. Thanks everyone. Can you talk about the timing of the bank redetermination, give us a general idea of what you expect the amount of the line to be how much cash you think you'll have in excess what you have to draw in order to pay for Hannathon?

Yes. That's a good question. We are working that process. We're about midway through working with the banks and looking at all alternatives, because we want to get the cheapest financing possible and the best financing possible. So we don't have an idea yet as to what the amount will be. We know it will be in excess of the $200 million and it will be enough to go ahead and close the Hannathon transaction. We already have commitments for that. But -- in combination with that, we're looking at all the alternatives available in the marketplace right now. And we should have that outline probably within the next 15 to 20 days. And know exactly the direction we're going to go.

That's helpful. I guess it kind of does make me wonder when you say cheapest and best. I mean, is there something other than a bank line that you're considering?

We're always looking for the best alternative from bonds, convertible bonds. We did an equity -- I mean, a debt offering earlier this year that was a very attractive financing. The RBL is a very attractive financing, but it does have a lot of restrictions on it in terms of hedging. We're very bullish right now on what oil prices are going to do over the course of the next 12 to 18 months. And so we're just going to cautiously go into this. And make sure that our – that is absolutely secure and that we have the best financing available for the strategy that we have going forward.

Okay. Thanks. Then could you just switching gears, could you put a number on the number of barrels that you feel were curtailed during the quarter?

Yes. Off and on, I would say, at one-time, we had 12 wells offline. But on an average, it would probably be in the neighborhood of 5,000 to 6,000 barrels a day or curtailed during the quarter.

No, that's helpful because that's probably more than I thought, and I suspect maybe others may be as well. So thank you. Okay. Thanks very much.

Thank you.

Thank you. This does conclude the question-and-answer session of today's program. I'd like to hand the program back to Jack Hightower, Chief Executive Officer, for any further remarks.

Well, I've been doing this for a long time, 50-something years of multiple public companies and executive committee and consulting for public companies. And honestly, this is one of the most exciting periods of time that I've had to report on. It's disappointing that our stock has gone down and I think it's the nature of algorithms and people looking at it and have their internal thoughts on where our production should be -- but when you're new and young in the equation to accomplish what we've accomplished going forward and getting our production where it is. It's a tremendous accomplishment. We are very excited about what's going on with the company, with the delineation of our production and reserves and consolidation. We're going to continue this activity and you're going to see 800-plus thousand barrels a day exit in 2023. So hopefully, you'll understand, my job is to make sure everybody makes money and that's what we're going to be doing for you. Thank you very much.

Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.