Good day and thank you for standing by. Welcome to the HighPeak Energy 2024 Second Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that today’s conference is being recorded. I would now like to hand the conference over to your first speaker today, Steven Tholen, CFO. Please go ahead.

Good morning, everyone and welcome to HighPeak Energy’s second quarter 2024 earnings call. Representing HighPeak today are Chairman and CEO, Jack Hightower; President, Michael Hollis; and I’m Steven Tholen, the Chief Financial Officer. During today’s call, we will make reference to our August Investor Presentation and our second 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 August Investor Presentation. I will now turn the call over to our Chairman and CEO, Jack Hightower.

Thank you, Steve and good morning, ladies and gentlemen and thank you for joining us today on this call. My prepared remarks will begin on Slide 4, of our August Investor Presentation. I’m very proud to report that HighPeak had another solid quarter of execution across the board as we continue to stay committed to our 2024 core values, which include maintaining discipline operations, strengthening our balance sheet and focusing on maximizing shareholder value. Operationally our drilling program continued to generate impressive production results and our operations team remains aggressively focused on optimizing daily operations and reducing our cost structure. Financially, we generated positive free cash flow for the fourth consecutive quarter, even taking into account that the second quarter will be our highest level of CapEx spend this year. And we continue to use our free cash flow to prioritize debt reduction while also executing our opportunistic share buyback program as we implement our primary objective of increasing shareholder value through improved operational results, our return of capital strategy and ultimately maximizing value through our strategic alternatives process. The second quarter, if you turn to Slide 5, was another strong operational success for HighPeak. Our production remained in the high 40,000 BOE range, which was a nice beat compared to our consensus estimate for the quarter. It is also worth noting that we were delayed bringing online a key pad, which pushed out some of our well turn on dates no later to later than we initially expected in the quarter. This materially reduced expected second quarter production volumes. Further, the quarter is off to a very strong start in the third quarter as production volumes have averaged over 52,000 barrels a day. And I want to emphasize that when you think of an average of 485 for the…

Thanks, Jack. Now turning to Slide 7. As Jack discussed, we are off to a great start this year shown by our higher-than-expected production volumes. Our first half production averaged approximately 49,100 BOE per day, which is an increase of roughly 8% compared to our 2023 annual average. Further, our third quarter is off to a great start as well at over 52,000 BOE a day. And our current two rig development program is expected to continue to support higher volumes throughout the remainder of the year as evidenced by our raising the production guidance. A few key drivers of this success, our new wells in our Northern and Northeastern extension areas in Flat Top have exhibited higher initial performance than we originally modeled. Again, as prudent operators, we always start off very conservative as we move to any new area. Our Judith Well, located in the Northeast corner of Flat Top and is referenced by the number one on the map, exhibited a peak 30-day average IP of over 1,350 barrels of oil a day plus associated gas. It has cued approximately 85,000 BOEs during the first 70-days of production. Our first 10,000 foot Wolfcamp A well located in our Northern expansion area, that is number two on the map, is currently making over 700 barrels a day of oil and is continuing to increase production as we can pull on the well longer. We also have a two well pad further to the East on this new acreage denoted by the number three. The Wolfcamp A and Lower Spraberry wells on that pad have been drilled, completed, and we expect to turn them online during the third quarter. The petro-physical analysis and cuttings from these two wells confirm that the reservoir is consistent with what we see in…

Thanks Mike and let’s turn to the next page on Slide 10. And I want to congratulate our operations team for a very successful quarter. This slide is an important slide to look back and see where you have come from, from a historical growth comparative analysis. And if you look at that we have been in business now four-years since we went public and we want to take the opportunity to highlight a few noteworthy company facts. As you can see, HighPeak has demonstrated a track record of significant financially responsible production growth on an annual basis over the past four-years. Production has increased by a factor of over 14 times during a short four-year life of the company. Think about that in terms of looking forward into the future. Through 2024, we have drilled 289 operated horizontal wells across our acreage position. Collectively these amounts to drilling over 3.5 million lateral feet and on a combined basis, our wells have produced over $50 million gross BOE since going public. This has led to HighPeak generating over $2.7 billion of revenue in over four-years, and we are now on-track to generate over $1 billion per year from this year on. So it shows you our history, but also can project into the future as to what our growth can be going forward. I think it is important to look back as well as look forward as you go forward in the future. So HighPeak and when you think about on the next slide, Slide 11, the takeaways I want to leave you with today is we are continuing to execute on all cylinders. Our asset base continues to deliver strong production results full of oily high margin barrels. We expect this trend to continue, which is why we are…

Our first question comes from the line of John White with ROTH MKM Capital. One second, please, John. Your line is now open.

Good morning, gentlemen. Congratulations on a nice production. In terms of lease operating expense, you talked about the pathways related to the tank battery, but weren’t there a higher amount of well workover expenses in the quarter?

I will take that one, John. Yes, absolutely. Thank you for the question, and good morning. So if you are referring to quarter-over-quarter, Q1 we averaged about $0.39 per BOE for workover expenses and we were closer to $0.69 or $0.68 this quarter. What drove a lot of that, again, we did 32% of our completions this quarter for the year. So if you look at kind of a general number and a good go forward kind of modeling number for HighPeak on a workover expense basis at our normal cadence it is somewhere between the $0.30 to $0.45 of BOE is kind of where I think we would run. So that $0.25 difference between each Q1 and Q2 was associated with a lot of the work that we did bringing these wells on and completing those 26 wells throughout the quarter. And whenever you do that, you do impact some of the wells on either side of what you are completing and that heavy cadence of completions did drive us to have to do some expense workovers on some of the offset wells around there. So that is what drove the change in Q2.

Okay. Thanks for that detail. I appreciate it. And I will turn the call back to the operator.

Thank you. Our next question comes from the line of Jeff Robertson at Water Tower Research. Jeff, your line is now open.

Thank you. Jack and Mike, I apologize, I missed part of your prepared remarks, so if you have answered these questions, I will read about it in the transcript if you want. But two questions, one on Slide 11, your last follow-up point, you talk about infrastructure supporting life of field development in Flat Top. And can you just talk about how that infrastructure investment that you have made would impact capital efficiency and returns going forward as you progress through your development program?

Yes, Mike, you can answer that.

You bet, Jeff. And thank you for that question, because It is often overlooked, the value of the infrastructure that you put in. Obviously, it helps us initially when we build our infrastructure to, for instance, our new Northern area where we built a lot of infrastructure to tie in one battery. So from a capital efficiency standpoint of the initial dollars you put in, it is pretty low day one. However, when we develop that area and have 35, 40 wells coming through that same infrastructure, your kind of dollar per completed lateral foot cost associated with future wells goes down dramatically. So as we have built out and have already spent the money on the vast majority of all the infrastructure that HighPeak needs, again, as Jack mentioned, for life of field, and that is for all of the multiple zone that we planned to drill and at whatever cadence here at one time we were running in six rigs. So again, in the future, depending on commodity price and balance sheet strength, if we ever wanted to increase activity, we could. And we have always kind of talked about the ability to pull back the range if oil prices were to go lower into the future. We have the leasehold position that is a very differential leasehold position that allows us to hold this whole 137,000 acres with just one rig or less running. So it is a very unique system that we have built. And as you pointed out, every additional well that we drill in the future gets the benefit from that money that we have spent over the last 3.5 years building out that infrastructure.

And I would add, Jeff, to that. If you think about we have got an infrastructure now that can go all the way up to 550,000 barrels of product to support our growth and when you think of 2,600 locations potentially, even if you go back to 1150 locations just in the Wolf A and Lower Spraberry and some other zones, that is expanding rapidly. And so we and others have invested almost $1 billion now on infrastructure here and that will allow us to expand all over across our entire acreage position and be able to handle with 100% recycling of the oil and the water as well as completions in the future and be able to handle that and dispose of the excess with our own saltwater disposal system. So that infrastructure now is basically in place. We will spend a few additional capital dollars going forward, but it will be very limited expenditures.

And Jeff, also on obviously, we reduced LOE in the guide down from a midpoint of $8 to a midpoint of $7 and again being conservative, we want to make sure that we meet and beat that as well. And you kind of see that on kind of Slide 7 on the production side where we are sitting with production in the guide that we increased the midpoint from 45,000 BOEs to 47,000. And since you weren’t on the you may have missed this in the prepared remarks, those two changes in guide over the 2024 calendar year equate to an EBITDA change of about $55 million and since we are in a free cash flow mode going forward this full-year as well as going forward, all of that additional EBITDA goes to free cash flow as well. So, again, all of this money and systems and infrastructure we have put in place is paying dividends now and will continue in the future.

Thank you. Our last question comes from Nicholas Pope with Seaport Research. One second please. Nicholas, your line is now open.

I was hoping you guys could talk a little bit about the uses of cash. And obviously, it is a good problem to have, but we are kind of looking at three items here with dividends, share repurchases the last two quarters and options to pay down debt. And I was curious how you are thinking about that going forward. Obviously, that debt is very high interest payments it is 20% of EBITDA. So curious like how you are kind of weighing that relative to these other to shareholder return options that you have in place?

Nick that is a great question and we are going to stick with our program to pay down debt. Now, we are going to keep the cash on the balance sheet because right now we have Make-Whole provisions and we want to make sure we pay that debt down at par. And of course, our Make-Whole provisions run out in March. We are fully aware that we could refinance and our costs at BB rating would go down to six-something, even with the new issuance in the seven-something percent range. But we have got to pretty well make that Make-Whole payment between now and March, so it is probably after that before we would consider changing. But our goal is to pay down debt. Now, we have the optionality of drilling more if oil prices happen to go way up. But we are going to stick with our program and stick with what we have been doing in the past. And eventually, if we don’t successfully have a strategic alternative by then, we would refinance our term debt and pay off our bonds and go forward. And, of course, the difference in the cost of that debt compared to what a bond would be today is almost $220 million a year of additional cash flow. So we have good optionality, but we are very encouraged by our strategic alternative process.

Got it, that is helpful. Switching to something a little more fun, these new wells. Curious, like going into these Northern - in the Northeastern kind of extensional areas on the newer acreage, I’m curious, as you went into those, were there any big questions that you thought needed to be answered and as you get the data from the production of these new wells, is there new zones, new productivity. How does that match up, I guess, with what the expectations were going into the wells and do you think that affects inventory and the numbers that we have talked about in the past?

I will let Mike answer that, and then I will follow-up if he leaves something out that I think is important.

Yes. So Nick great questions. Again, any operator, as you move more than a couple miles away from known production, we are all kind of engineers in the background, so we like to be conservative. When we say they beat expectations, yes, these wells beat the expectations they were using as we were modeling to make sure we had enough risk for that kind of two-mile walkout or as we went North, to go yet another two miles North of where we were. But from a petro-physical standpoint, from log analysis, from the cuttings, everything suggested that it should be just as good as what we had down in what we call the core of the Flat Top area. So, were we not expecting to see what we did? No, the answer was we fully expected to get this result. And to answer your question about additional zones, these wells were Wolfcamp A well and Lower Spraberry. Now, I have mentioned it at the end of last quarter that we were most likely going to drill a Middle Sprayberry well sometime in the near future. Well, we have already drilled and completed our first Middle Sprayberry well, which sits down in kind of the center part of Flat Top, and we are running the pump in the ground today. So we will have some information for the third quarter call. Again, there is offset wells touching the west side of our acreage block, and as we drilled that Middle Spraberry well, all things were encouraging from cuttings to oil cut that we saw in some of the returns while drilling. So again, we should be able to give an update on that additional zone that we have targeted in Flat Top. But no, these two new areas are acting as we suspected they would and as they should for modeling. It is just when we do guidance we always try to put a little left in there for the good guys.

The only thing I would add, Nick, to what Mike said is from a geological and petro-physical and oil-in-place analysis, we feel like our whole acreage position, even moving to the east. And as you can well imagine, we still have certain companies that think as we move East that the production is going to decline and yet our Judith well, which is our furthest eastern well outside the well in Scurry County, the Virginia well, is our most successful well. And it was a little bit of we anticipated potentially, but it is turning out to be one of our very best wells and definitely adding more locations to the east and at least being able to prove that up to potential suitors and so that was an exciting arrangement. And then going forward, we are probably going to drill another Wolf B well and we will drill some more Middle Spraberry wells and we will probably drill another well down to the South at Signal Peak in the Hutto zone, the Wolfcamp C zone. So a lot of good things are happening for us and that definitely adds to the number of locations that we have.

Got it, that is all very interesting. I appreciate the time. Thanks guys.

This concludes the question and answer session. Thank you for your participation in today’s conference. This does conclude the program. You may now disconnect.