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. 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 disciplined 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 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 48,500 for the last quarter and then already in the third quarter here, we are over 52,000 barrels a day and seeing impressive early results from our recent Northern Extension wells in our Flat Top operating area. Mike will provide additional insights into our continued strong production results later in the presentation. But after achieving an impressive first quarter reduction in lease operating expenses, our operations team continued to maintain a significant sub-seven dollars per BOE cost level, even considering the lower production volumes due to the pad delay. Our continued operational success led to HighPeak maintaining its peer-leading cash margin which equated to a net back for the quarter of over 80% of our realized price on a BOE basis. And our cash margins per BOE continue to be over 65% higher than our peer average, which Mike will emphasize is very important to our income stream and our success as a company. As a result of our solid production volumes and sustained lower operating expenses, we generated another strong quarter of cash flow and remain in a very healthy financial position. We also reduced long-term debt by another $30 million at par and continued to opportunistically implement our share buyback program by acquiring over 413,000 shares during the second quarter. Now if you will turn to Slide 6. This is really an important slide, because we are exceeding our expectations. As a result of our successful first half 2024 results, we are updating our 2024 ranges in a few key categories. We are raising our production guidance to 45,000 to 49,000 BOE a day, an approximate 4.5% increase compared to our initial 2024 range. Our production volumes continue to remain strong, and we are confident in lifting this bar for the remainder of the year. We are also lowering our lease operating expenses per BOE to $6.50 to $7.50 which is a 12.5% reduction from our initial expectations. Our operations team has done an exceptional job optimizing our fill wide program throughout the first half of this year and I’m hopeful that there are incremental savings that we will continue to see throughout the remainder of the year. We are also narrowing our capital budget from our initial band of $85 million down to a band of only $40 million. This slight increase is due to some additional infrastructure projects that we undertook primarily related to our Northern extension area and Mike will provide some additional color on this in a few minutes. The key takeaway is that we have had a very impressive start to the year with our results exceeding initial expectations and we are confident in our ability to continue to achieve higher production volumes and lower costs for the remainder of the year. With that, I will now turn the call over to our president, Mike Hollis, to provide an operational update as well as some additional details supporting our improved guidance.

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 conservatively 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 accrued 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 our core Flat Top area. So we continue to be very encouraged and excited about this Northern area of the field. And in addition to the successful new wells at our Northern extension areas, we are continuing to see strong well performance across our entire acreage. The operations team is firing on all cylinders and we continue to see better uptime and lower costs across the board. Now turning to Slide 8. As Jack previously mentioned, our team has been intensely focused on reducing costs across the board and they delivered again this quarter. HighPeak’s beaten rates to production and lower LOE guidance assuming second quarter pricing equates to $55 million of additional EBITDAX as well as free cash flow for 2024. Some key drivers to our step change in LOE year-over-year are optimization of our chemical program throughout the field; our operations team has been keenly focused on this initiative and continues to make further strides. Chemical cost is a significant component of our OpEx. And as I mentioned last quarter, we continue to fully exploit our world class life of field infrastructure system. Part of this exploitation is being able to dispose of 100% of our produced water that is not being used for recycling through our company-owned system and not having to rely on any third-party disposal. This drives significant OpEx cost reductions as third-party disposal is inherently more expensive. On that note, a key contributor to our higher LOE in the second quarter compared to the first was the central tank battery delay that Jack commented on earlier. The battery commissioning was delayed about a month. We turned those wells on in the second quarter, had all of the usual costs associated with production and no BOEs to divide by. But as you can see in our quarter-to-date production numbers, those wells are now contributing. Had the wells come on a month earlier, our LOE would have been more in-line with the Q1. Our overhead electric power distribution system continues to pay huge dividends for HighPeak. Not only does it provide more reliability to our operations, i.e., uptime, but we have expanded it to the point to where we have been able to tie in extension area wells into the overhead electrical system at startup versus having to run new areas of the field on more expensive generator power until the overhead electrical system is ready. And it is no secret that electrical power supply is getting tight in the Permian Basin. And additional power project timelines are being substantially pushed out. Our team has done a fantastic job in recognizing this situation well in advance, taking the initiative to secure an abundant supply and construct a distribution system that efficiently delivers reliable power across our entire field. HighPeak is in a great position for life of field development even at an increased development cadence. In addition, our solar farm is now fully operational and is providing consistent renewable power to supplement our Flat Top overhead electrical system. One thing for sure, there is no shortage of abundant West Texas sunshine during the summer months, and now we are able to exploit this to our material benefit. The solar farm will also help insulate our power costs during electrical spot pricing spikes that the region periodically faces throughout the summer months. Again, our operations team has done a tremendous job over the past few years in building out our world-class infrastructure and optimizing all field operations, all of which are now starting to materially improve our bottom line. Now turning to focus on our capital budget for a moment. As we previously mentioned and messaged, our 2024 capital program was first half weighted and that is due to a number of reasons. Our first half turn in-line cadence is slightly higher at 55% of our annual guide range. This is primarily due to the additional wells that we carried into this calendar year from running a three rig program during the fourth quarter of last year and partially in Q1 of 2024. Furthermore, our second quarter turn in-lines were approximately 32% of our entire 2024 program which speaks to Q2 being our hottest CapEx quarter for the year. In addition to the extra wells turned in-line during the first half, our infrastructure projects were also first half weighted. As we extended our systems to our new northern acreage areas in Flat Top, these extension projects provide immediate returns and were constructed in a manner to support full development of these new areas with only incremental future capital requirements. Our facility spend was also first half weighted as we constructed new tank batteries in these extension areas of the field. As we progress in our development plan and drill more wells in these areas, our facility cost on a dollar per foot basis will drop considerably. DC&E costs are holding steady at prices that we realized during the first quarter. As the industry has seen a reduction in rigs and Frac Spreads over the last several quarters, I would expect some additional softening this year, albeit small. And to that fact, we have narrowed our CapEx budget for the remainder of the year and feel very confident that we will remain within our guided range. Now turning to Slide 9, HighPeak’s margins per BOE continue to command a lead among our peer group. Our second quarter unhedged EBITDAX margins remain strong at $50.07 per BOE, which continues to be over 65% higher than our peer group average. The chart on the slide highlights that HighPeak’s EBITDAX margin over the past five quarters has averaged over 60% of average NYMEX oil prices. Or said another way, for every BOE that high peak produces, we realize a net profit of approximately $50, assuming an $80 NYMEX index price. But in comparison with our peer group, who on average only generate profit margins of roughly $30 per BOE at an $80 NYMEX oil price. Another way we like to evaluate our margins is to compare EBITDAX margin per BOE as a percentage of our realized price per BOE. This is less of a comparison versus our peers and more of a view of how efficient we are at converting our produced BOEs into net profit for HighPeak. Our second quarter margins show that for every BOE that HighPeak produced, we converted over 80% of the realized sales price per BOE into net profit for the company. We have built a very efficient machine here at HighPeak, which will allow us to cost effectively convert our deep inventory of undrilled locations into substantial profit. And as we always say, not all BOEs are created equal; our high oil cut and our approved cost structure will allow HighPeak to continue to generate differential profits for decades to come. With my comments now complete, I will turn the call back over to Jack.

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 we 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 into 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 confident in raising our production guidance. Throughout the past year, we have been intensely focused on optimizing our field-wide operations, expanding our world-class infrastructure system to reach all areas of the field and as Mike likes to say, lots of production going forward. These have led to the realization of significant operating cost reductions as evidenced by our results through the first half of this year. We expect to maintain this lower step change in operating expenses going forward and as such are confident in lowering our LOE guidance range. Second, we have positioned the company for optimal value creation. We have amassed a soluble, highly contiguous acreage position, prime for large-scale development. It is truly one of the few remaining opportunities of significant scale in the most sought-after basin in the country, the Permian Basin. We rapidly increased our oil-weighted high-margin production and reserves to a significant level. We have delineated a long runway of high-value inventory, which spans our entire leasehold position. The scarcity of sub $50 per barrel breakeven inventory amidst the current market trend of extreme consolidation puts HighPeak in a very unique and lucrative position. We have built out a world-class infrastructure system, which will support life of field development and helps insulate our peer-leading profit margin for decades to come. I can’t really provide specific details at this time, but I do want to say that our strategic process is making significant progress and I’m very excited about what the future holds for HighPeak and our shareholders. With our comments now complete, I will open the call up to questions from analysts.

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 zones 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 1,150 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 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 less 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.