Thank you for standing by and welcome to the HighPeak Energy Third Quarter 2022 Earnings Conference Call. [Operator Instructions] And now I would now like to introduce your 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 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

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…

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…

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 [indiscernible] 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…

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

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?

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 [indiscernible] 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.

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.

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.

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?

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 [indiscernible] is a good round number to think about.

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.

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.

Okay, thank you.

You bet.

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

Good morning, everyone.

Good morning.

Morning.

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.

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 [indiscernible] 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.

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.

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 [indiscernible] 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.

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.

I appreciate that Jack and Mike as well. I'll hop off. Thank you for the time.

Thank you.

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.

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?

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 [indiscernible] 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.

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?

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.

Thank you.

You bet.

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.