Good day and thank you for standing by and welcome to the HighPeak Energy 2023 Second Quarter Earnings Call. At this time, all participants are in a listen-only mode. After the speaker’s presentation there will be a question and answer session. [Operator Instructions] And please be advised that today’s conference is being recorded. I would now like to hand a conference over to your speaker today. Steven Tholen, CFO. Please go ahead.

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 HighPeaks 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 is 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 and reduce 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 crews. We will maintain a two rig program and utilize one to two frac crews throughout the remainder of this year. And until our debt refinance has been completed, it is too early to discuss our 2024 development program. However, it is still our intention to finance a 100% of…

Thanks Jack. Again, staying on this slide over the last three years, as Jack mentioned, we had a production growth CAGR of over 175%. And as we have 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 high peak 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 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. And 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 high peak produces an oilier Boe in 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 750 in 2024. However, if we normalized high peak second quarter LOE to our peers by using an economically equivalent amount of the average peers Boes as the denominate or as denominator, our LOE would equate to $5.25 for Boe, this 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…

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 $80 oil price. If you add in additional production going into the fourth quarter in 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 a 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 pay down 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…

[Operator Instructions] 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. 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 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. And 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 and 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 kind of levels and grow it a little bit into 2024 and be able to hold that for over a decade and generate significant three 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 was 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, and net of a little over a $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 rig 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, that will be an issue on a go forward basis.

Just looking at a 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 kind of caused that drop despite the higher level of activity, if that makes sense.

This is Mike. And you know, as we reduce activity, of course, a lot of dollars and a lot of activity has to take place to bring these wells online. So 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 all. We are actually seeing kind of single digit overall reduction in costs from services, mainly driven from fuel, 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 were also able to increase the percentage usage of all of our call saving initiatives. For instance, today we have a 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, you will see that it is going to be 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 kind 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 kind of talk through that production profile that you saw in one of the earlier slides. Early on, whenever you all said, and you are only producing 30,000 to kind of 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 kind of 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 kind of 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 would 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. And then 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 well 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. And 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 includes the conference call. Thank you for participating and you may now disconnect. Have a great day.