Good day and thank you for joining us for the HighPeak Energy 2023 Second Quarter Earnings Call. All participants are currently in a listen-only mode. Following the presentation, there will be a question and answer session. Please note that this conference is being recorded. I will now turn the call over to our speaker today, Steven Tholen, CFO. Please proceed.

Good morning everyone and welcome to HighPeak Energy’s second quarter 2023 earnings call. Representing HighPeak today are Chairman and CEO, Jack Hightower; President, Michael Hollis; and Vice President of Business Development, Ryan Hightower, 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 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. We want to thank you for joining our call today regarding our second quarter earnings. My prepared remarks will begin on page four of our presentation. This is perhaps one of the most exciting presentations in the history of HighPeak. As you can see, we are substantially a different company today than we were just a few short months ago. Not only is this an exciting time, but we have also recently achieved two very important company milestones. Number 1, our production has averaged over 50,000 barrels a day, BOE equivalent per day thus far in the third quarter. That is an 18% increase over our quarter average and a 35% increase compared to our first quarter average. This increase is in accordance with our projections, and continues to track our internal expectations. Number 2, going forward, we are now delivering positive free cash flow from operations. And at current prices and our two rig cadence, we expect to generate excess cash flow over our CapEx spend this quarter. This is a major achievement for the company and for our long-term strategic plan. From this point forward, we intend to finance all of our drilling activity through operational cash flow, and generate significant free cash while reducing our outstanding debt over the course of the next 12 months. I would say that leads to capital discipline. In accordance with our updated development plan, we are currently running two rigs and one frac crew. We will maintain a two rig program and utilize one to two frac crews throughout the remainder of this year. Until our debt refinancing has been completed, it is too early to discuss our 2024 development program. However, it is still our intention to finance 100% of our drilling program through operational cash flow, while generating material free cash for debt reduction. We will talk more about that as we go through the presentation. Coming off a more active drilling program in the first half of the year, we had an additional 42 gross wells in various stages of drilling and completion at the end of the second quarter. These wells will be turned online throughout the second half of the year, and will translate to additional production growth throughout the remainder of the year. At current prices, we are approximately one times debt-to-EBITDA leverage ratio today. As you can see from tables on this slide, by the end of this year, we should be under one turn of leverage and generating roughly $1.1 billion of cash flow on an annual run rate basis, utilizing $80 oil. Now turning to the next page, Slide 5. This slide is really showing the rock in our area, the growth of our production. If you think about just a few years ago, we were at 3000 barrels of oil equivalent per day. And today, after a 175% compound annual growth rate, we are up to over 50,000 barrels a day. Keep in mind that comes out of 200 producing horizontal wells. There are almost 50 more wells coming online between now and the end of the year. We also continue to maintain our sustained peer-leading profit margin, which differentiates us from other companies. So if you look at this, you have to make the assumption that this rock in this area is very, very good. It is very profitable and it meets anybody’s Tier 1 asset base. Eastern Howard County is fantastic. And as we look at the accomplishment of this level of growth while staying at around one turn of leverage, even while considering volatile commodity prices over the last three years. Now if you will turn to Slide 6, I’m going to talk a little bit about the margins to continue outpacing the peers. We stated that we were actually improving on our profit margin. This is a good example. In fact, today our production volume of 50,000 barrels a day compared to our peers is worth the equivalent of 80,000 Boe per day and that is just phenomenal. That is almost a 60%, 59% increase compared to our peers. So as mentioned on our first quarter earnings call, our margin will continue to expand, and the reason is because of our oil cut. We have a tremendous oil cut, and compared to our peers that end up with almost 50% gas. After a year, we continue having 93% liquids. We also expect to expand and continue expanding our margins on our forecasted production growth and our LOE reduction initiatives further kicking in. I’m going to turn the call over to Mike Hollis and he is going to spend even a little bit more time explaining these margins to you as he goes forward in talking about operations. Mike.

Thanks Jack. Again, staying on this slide over the last three years, as Jack mentioned, we had a production growth CAGR of over 175%. As we've mentioned in the past, not all Boes are created equal and our Boe mix is quite a bit different than our peers. We are 84% oil and 93% liquids. This product mix, coupled with our low-cost structure, generates margins per Boe roughly 60% higher for HighPeak compared to our peer group. Our gearing to oil price is significantly higher than our peers. If you believe that the underinvestment in supply over the last couple of years in combination with the growing global demand will further affect oil prices disproportionately to natural gas prices, our margin will continue to expand compared to our peers. As our production volumes increase throughout this year, we will continue the implementation of our cost-saving initiatives and our cash costs will trend lower, further expanding our margin. LOE for oil companies tends to run higher than our gas company peers on a Boe basis and HighPeak produces an oilier Boe than most every other oil company. So you would expect our LOE to run higher on a per-unit basis. Second quarter LOE was roughly $8.40 per Boe; we expect this to trend closer to $7.50 in 2024. However, if we normalize HighPeak's second quarter LOE to our peers by using an economically equivalent amount of the average peers Boes as the denominator, our LOE would equate to $5.25 per Boe, this is extremely competitive. We turn now to Slide 7. We have walked you through the production ramp on Slide 5. Quarter-to-date production is over 50,000 Boes per day, again, very oily rich. Our current 2023 guide is to exit this year at 57,000 Boes per day. With the two rig program, we plan to turn in line roughly 46 gross additional wells in the second half of 2023. There were 42 as Jack mentioned at the end of the quarter, of which all operated wells are Wolf Camp A and lower Sprayberry. The map to the right side of this slide highlights where the second half of 2023 HighPeak operated wells are located, all in known areas, offsetting existing production. Our development focus will continue to be on co-developing the Wolf Camp A and Lower Sprayberry Formations, which at our current two rig cadence, we have over 12 years of inventory in just these two primary zones. These additional turning lines in our continued excellent well performance support our 2023 average and exit production guidance. Nothing is ever a slam dunk in the operations world, but you can see a very real path to meeting and exceeding our production targets for 2023. We continue to reap the rewards both economically and environmentally from our significant investment in infield infrastructure. The capital has already been invested to allow HighPeak to operate in a very efficient manufacturing mode. Our Highline electrical infrastructure and the development of our solar farm have positioned us to mitigate the need for high-cost rental generators when turning on new wells and enable us to drill using highline power, reducing both our diesel emissions and power costs. Our OpEx will continue to trend down as our infrastructure is further utilized. We will continue to electrify all prime movers throughout the field, reduce third-party SWD takeaway volumes, and optimize our chemical programs. Simultaneously, we will continue to benefit on the CapEx side of the equation from our water recycling system, electrical grid, and our 100% utilization of local wet sand. And with my comments now complete, I will turn the call back over to Jack.

Thanks, Mike. If you will turn to Slide 8 on your presentation, all of these are looking at what we have consistently increased the value of our asset base. Most of our growth has been through the drill bit. We have had a few acquisitions, but these acquisitions have added very little, at least at the time we made the acquisition, and now we are starting to realize the benefit of these acquisitions. Our estimated fourth quarter run rate EBITDA is projected to be in the range of $1.1 billion at an $80 oil price. If you add in additional production going into the fourth quarter and next year, it is much higher than that. Our projected leverage ratio by the end of the year should be less than one time, one turn at the same oil price. We are still bullish on oil prices overall, both in the near and medium term. Each $1 barrel increase in oil price above $80 equates to $16 million of annualized EBITDA. So a $10 barrel increase in price to $90 would equate to another $160 million of additional annual EBITDA for HighPeak. That is a considerable amount of additional cash flow that can be used for further debt paydown or for reinvestment or a combination thereof. In connection with our growth profile and our growth in production, the value of our approved reserves is also continuing to grow. Our approved reserves at midyear 2023 have increased to $2.8 billion at a flat $80 oil price based on our internal midyear roll forward reserve report. Our asset coverage, our proved reserve value absolutely supports our current outstanding debt. In addition, on a go-forward basis, we will be generating free cash flow, which will further lead to rapid deleveraging. The company is very healthy and has a pristine balance sheet going forward. Now turning to Slide 9. There has been a lot of confusion relative to our obligations concerning our debt metrics. Last month, we completed a $155 million equity raise. Wherein consistent with our past history, both our management team and significant stakeholders participated at substantial levels. In fact, we invested almost $108 million of the $155 million, thereby not suffering dilution. The capital raise from this offering along with our June revenues was used to catch us up on our outstanding payables and to enhance our near-term liquidity. This raise plays a crucial role in positioning the company to receive more favorable terms on our debt refinancing and to effectively execute our comprehensive long-term strategic plan. Relative to confusion in the marketplace regarding certain dates associated with our credit facility requirements, I want to take a few minutes to give a detailed explanation of this situation. And this slide gives you an example. In conjunction with our recent equity raise, our credit facility bank group approved amending to provide for a postponement from June 1st to September 1st of the company’s obligation to redeem, extend or submit a plan for repayment of our February 2024 notes. Please note, this requirement is only in regard to our February 2024 notes and does not require the redemption or extension of our November 2024 notes. I will say, it is our intent to redeem or extend both sets of existing notes, but the RBL requirement is only in regard to the February notes. I would also like to say that we have a great working relationship with our bank group, who have been very supportive throughout this process. I would like to thank them for their continued support as we work diligently to extend our debt maturities. As mentioned, we are working on a comprehensive debt refinancing structure, which will meaningfully extend our debt maturities. It is our goal to extend these maturities into 2026 or later. Similar to our recent equity raise, there is a lot of interest from the investment community in participating in our debt refinance. I know some people have been thinking that it is going to be difficult to refinance this debt. With the balance sheet and the strength we have in our growth and our production, we have multiple term sheets in hand, which will meet our financial needs. We are simply working swiftly and diligently to negotiate the most favorable structure in terms for the company with the right group of lenders, which will allow us to achieve our long-term goals. Keep in mind that the current status of the company is completely different today. Our equity raise enhanced our near-term liquidity position, and we are now cash flow positive from operations on a go-forward basis. As mentioned, we are producing in excess of 50,000 barrels per day equivalent and the value of our proved reserves has increased substantially from our year-end 2022 report providing substantial coverage and excess coverage for our current debt level. Our current EBITDA run rate at today’s price is approximately $1 billion on an annual basis, which equates to a very modest leverage ratio of one term right now today. Of course, this will go down as we go forward into this year. We expect the leverage ratio to decrease over time as we use our free cash flow to reduce debt. One additional point I would like to mention here is if we decide to stick with our current two rig program in 2024 and go into more of a production maintenance mode at current commodity prices, we will project to generate roughly $500 million of free cash flow in simply the next 12 months into next year’s business. This is after applying interest expense and factoring in our current dividend, so we could easily pay down our debt by over 50% in the next 12 months if we wanted to. This does not include any debt reduction benefits from the free cash flow that we anticipate generating throughout the remainder of 2023 either. So again, due to all of the reasons I just mentioned, I’m extremely confident that we are very financially healthy and that we should resolve this debt refinancing shortly. Please also understand that due to the late stage of negotiations and the confidentiality associated with the terms and the potential investors, I will not be able to discuss the status or details of our financing or refinancing project any further at this time, and unfortunately, will not be able to answer any questions during the question-and-answer session on this subject. However, I will say the management remains very confident in resolving this refinancing with full resolution and we could accept any of these term sheets. We are simply looking for the very best opportunity. Page 10 is the slide to wrap up, and as you can see, we continue to check all the boxes or in this case the circles in terms of our high liquids rating. That puts us in competition with all the top-tier production in the other mid parts of the Permian Basin and the Midland Basin. We have a prime oil weighted Permian asset base with high return well economics, continuous acreage, which was set up to provide maximum capital efficient long-term development. In fact, our drilling at Signal Peak and in Flat Top are providing internal rates of return of 15% to 20% in the various areas, and these are tremendous returns on the Wolf Camp A and lower Sprayberry zones. We have achieved significant scale at over 50,000 barrels of oil a day or an economic equivalency basis with our average peers roughly 80,000 barrels a day. Our financial and credit metrics are in good shape right now with visible near-term improvement on the horizon. We have strong PDP and improved development coverage, and we will now be generating free cash flow from our operations going forward. We have de-risked our acreage position and have over 12 years of premium inventory just in the Wolf A and lower Sprayberry zones at our current two rig cadence. The word de-risk is very important here because we have now drilled wells across our entire acreage block, both in the north and down to the south. That should mean a lot; these wells are producing at the level that they are producing and that our rocks are good. In addition, our management team has continued to demonstrate alignment with our public shareholders through our high equity ownership in the company, and we will remain confident in our ability to resolve our debt refinancing project very soon. Hence the reason we have invested a lot of our personal dollars in the company. Our primary focus remains on generating free cash flow on a consistent basis going forward and fortifying our balance sheet. Considering all these points, I remain extremely confident in our ability to create additional value for our shareholders. One thing I would like to say simply is I always want every shareholder, small and large, to have a high return on their investment. It concerns me that we have had so many shareholders that have shorted our position, and yet all I will say along those lines is to me, that is a very dangerous position to be in light of oil prices moving with the performance we have in our production and the type of rock and returns that we have. I wouldn’t be doing that. That is very high risk, but you have to make your own decisions. But you can see we are definitely on a different page in terms of our management and our evaluation of what is happening in the field. So now, I'm just with my comments complete, I will open it up for questions if anybody has any questions. Thank you.

Your first question comes from the line of John White of Roth Capital.

I see on Slide 7, you have got development drilling focus will be the Wolf Camp A and the lower spray, but is that true for Flat Top and Signal Peak or could you talk about what formation characteristics may be different between those two areas and the Wolf Camp A and the lower Sprayberry?

Yes, John, I have Mike answer to that question.

You bet. Thank you, John. The near-term development plan, call it for the next year or so, two years, is to drill and co-develop A and lower Sprayberry, both in Flat Top and Signal Peak. From an economic standpoint, the A and lower Sprayberry look very similar in both areas, they are almost a lay down economically, so again, it is more fungible as to where we spend the CapEx dollars, whether it is Signal Peak or Flat Top. And you can see the wells we will have coming on throughout the rest of this year and kind of the development plan for 2024 is to continue kind of a manufacturing mode, method of mowing down the A lower Sprayberry with 12 years of inventory in just those two zones. Earlier when it was mentioned, the IRR for these wells, that was actually a net present value discounted at 10% of about $15 million to $20 million per well. So we get our money back that we spent in roughly $20 million of well, so highly economic area, lot of run room for the two rig program over a decade in just those two primary zones. So again, we are very excited about being able to hold production at these kinds of levels and grow it a little bit into 2024 and be able to hold that for over a decade and generate significant free cash flow.

Our next question comes from the line of Nicholas Pope of Seaport Research.

I was hoping you guys might talk a little bit about, kind of the progression of working capital, over the near-term. I think with everything, with the equity raise, I think there were some current ratio metrics that were pushed out and I think accounts payable kind of been built up. I was curious once the cash comes in from the equity raise, what that progression looks like over the kind of the second half of the year with working capital?

Sure, Nick. This is Steve. So with the equity raise, net of a little over $150 million, we use that to bring our accounts payable current and enhance our liquidity position a bit. As we are in a position now of generating free cash flow, our positive cash flow. We participate as we move forward. We will continue to bring the payables down. That basically is a reflection of the reduced drilling program that we have going from five rigs at the beginning of the year down to two rigs and down to also from four frac crews to two frac crews. In terms of the current ratio, we did not meet the current ratio at the end of June. We don’t anticipate that to be an issue on a go-forward basis.

Just looking at CapEx for the quarter. I mean, I think you brought online 10 more wells in 2Q relative to 1Q, similar number of wells drilled, but CapEx was down $80 million. So I was hoping maybe you guys could talk a little bit about well costs and maybe what caused that drop despite the higher level of activity, if that makes sense.

This is Mike. As we reduce activity, of course, a lot of dollars and a lot of activity have to take place to bring these wells online. In the first quarter, a lot of the work for the wells that come online in the second quarter were done and paid for in the first quarter. So that is part of why you see so many wells come on in the second quarter and the cost dramatically different on a per well turned inline basis. But when you kind of step back in general and just look at what the OFS pricing is doing, things have leveled off. We are actually seeing kind of single-digit overall reductions in costs from services, mainly driven from fuel and tubular goods. Of course, we are starting to see a little softening on horsepower and rig rates, but it is kind of a twofold answer here. As we have reduced our rig count and frac spread count, we have also been able to increase the percentage usage of all of our cost-saving initiatives. For instance, today we have 100% of our frac sand needs covered with our local wet sand. Whereas when we were running four, we had to supplement it with some spot pricing. Kind of goes to the same point when you plug in just one drilling rig to Highline Power, that is 50% of our fleet today. So we are able to utilize more of those cost-saving initiatives. So what you will see on a per foot basis is larger than that kind of low-single-digit just OFS pricing reduction because we get to see the higher usage of these other pieces. So think somewhere in the kind of 4% to 5% range is what we are seeing today.

I’m going to squeeze one more in if you let me. Were there any, I think kind of over the past year you have had a number of one-time impacts from shut-ins or frac offsets. Did you see any of that in 2Q or did you all think this was a fairly clean quarter from a production standpoint?

So, Nick, on any one day, you always have, whenever you are fracking wells near existing production, you will have shut-ins. Obviously going from the four frac crews down to one, you have less shut-in. But again, as we talk through that production profile you saw in one of the earlier slides. Early on, whenever you all said, and you were only producing 30,000 to 20,000 barrels a day and you have to shut in 10,000 to 12,000, it is very impactful when you are producing over 50,000 barrels a day and you have to shut in 2,500 to 3,000, that is always going to follow that frac crew when you are offsetting existing production. So to that, I will say it is very kind of ratable to what you will see in the future. Unless we go and add a lot more activity, and then you can look out about two or three months out from adding a lot of rigs. When you would see a little bit more of that water out effect as we were to accelerate in the future. But from here, holding a two rig program, this is very ratable; it will be up into the right for growth as opposed to kind of the saw-tooth pattern you saw in the past.

Your next question comes from the line of Jeff Robertson of Water Tower.

I joined the call late, so I missed your prepared remarks, but I was curious whether or not you have any incremental data points around the eastern peripheral acreage that you all have that maybe impacts your thinking or the prospectivity of HighPeak’s position?

You bet, Jeff. We mentioned kind of in the past our farthest northeast pad that was drilled, and this is up in Flat Top. It is called the Conrad pad. It is a Wolfcamp A and a lower Sprayberry. Both of those wells kind of IP somewhere close to a thousand barrels of oil a day plus associated gas. So again, that was kind of a seven-mile step out from known production back to the west. Again, geologically, we knew the rock was good. We have all the petrophysics and seismic data and core analysis. So we felt comfortable doing that, but we proved that here several months back or quarters back. Even if you go all the way into Mitchell County up in Flat Top, Bay Waters and all sit operator to us, to the south and to the east. They have drilled some wells right on the very eastern flank of our acreage block of wells going north and wells going south. Both of those wells, again, tested close to a thousand barrels a day and are still cleaning up because they are pretty recent wells. So again, we feel confident across our entire acreage block and Flat Top. Now if you go down to Signal Peak about midway through, about 65-ish percent of the way from west to east and Signal Peak that is where we have our easternmost A and lower Sprayberry. Well, and for the foreseeable future, all of our A and Lower Sprayberry drilling that we plan to do in Signal Peak will be from about that three-quarters or two-thirds of the acreage position from west to east back to the west. So it will be on known acreage where we have production kind of bookending each side of that. That is where all of our A and Lower Sprayberry inventory that is listed sits within. So again, we feel very confident in that 12-year inventory life of those two zones with a two-rig program.

Thank you so much, Jeff. And there are no questions at this time, and this concludes the conference call. Thank you for participating, and you may now disconnect. Have a great day.