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. To ask a question during the session, you will need to press star one one on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star one one again, and please be advised that today's conference is being recorded. I would now like to hand the 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; 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 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. Please refer to the cautionary language 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. 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 one, our production has averaged over 50,000 bbl a day, BOE equivalent per day, thus far in the third quarter. That's an 18% increase over our second 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 two, going forward, we are now delivering positive free cash flow from operations. 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're currently running two rigs and one frac crew. We'll maintain a two-rig program and utilize one to two frac crews throughout the remainder of this year. Until our debt refinance has been completed, it's too early to discuss our 2024 development program. It's still our intention to finance 100% of our drilling program through operational cash flow while generating material free cash for debt reduction. We'll 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 1x 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 1 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 five. 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 3,000 bbl of oil equivalent per day, and today, after a 175% compound annual growth rate, we're up to over 50,000 bbl a day. Keep in mind, that comes out of 200 producing horizontal wells, with 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. If you look at this, you have to make the assumption that this rock in this area is very, very good, it's very profitable, and it meets anybody's Tier One asset base. Eastern Howard County is fantastic. 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'll turn to slide six. I'm gonna talk a little bit about the margins to continue outpacing the peers. We stated that we actually were improving on our profit margin, and this is a good example. In fact, today, our production volume of 50,000 bbl a day, compared to our peers, is worth the equivalent of 80,000 BOE per day, and that is just phenomenal. That's almost a 60%, 59% increase compared to our peers. 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 tremendous oil cut, and that, 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 kick in. I'm gonna turn the call over to Mike Hollis, he's gonna spend even a little bit more time explaining these margins to you as he goes forward in talking about operations. Mike? You bet. Thanks, Jack. You know, 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'll 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. 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 normalized HighPeak's second quarter LOE to our peers by using an economically equivalent amount of the average peers' BOEs as the dominate-- or as denominator, our LOE would equate to $5.25 per BOE. This screams extremely competitive. You turn now to slide seven. We have walked you through the production ramp on slide five. 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 2-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 Wolfcamp A and Lower Spraberry. 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 Wolfcamp A and Lower Spraberry formations, which at our current 2-rig cadence, we have over 12 years of inventory in just these two primary zones. These additional turning lines and our continued excellent well performance supports our 2023 average and exit production guidance. Nothing is ever a slam dunk in the operations world, 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 in-field 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 has positioned us to both mitigate the need for high-cost rental generators when turning on new wells 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. With my comments now complete, I'll turn the call back over to Jack. Thanks, Mike. If you'll turn to slide eight in 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've had a few acquisitions. These acquisitions have added very little, at least at the time we made the acquisition, and now we're starting to realize the benefit of these acquisitions. Our estimated fourth quarter run rate EBITDAX is projected to be in the range of $1.1 billion at $80 oil. If you add in additional production going into the fourth quarter and next year, it's much higher than that. Our projected leverage ratio by the end of the year should be less than 1x, one term at the same oil price. We're 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. A $10 a barrel increase in price to 90 would equate to another $160 million of additional annual EBITDA for HPK. That's 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 proved reserves is also continuing to grow. Our proved reserves at mid-year 2023 have increased to $2.8 billion at a flat $80 oil price, based on our internal mid-year 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 nine, there's been a lot of confusion relative to our obligations relative to 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, we invested almost $108 million of the $155 million, thereby not suffering dilution. The capital raised 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, providing for a postponement from June first to September first 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, it is our intent to redeem or extend both sets of existing notes. 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'd 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's a lot of interest from the investment community in participating in our debt refinance. I know some people have been thinking that it's gonna be difficult to refinance this debt, but 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 bbl per day equivalent, and the value of our approved 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 1 term right now today. Of course, this goes 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'd 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. Again, due to all of the reasons I just mentioned, I'm extremely confident that we're 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 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 that management remains very confident in resolving this refinancing with full resolution, and we could accept any of these term sheets. We're simply looking for the very best opportunity. Page 10 is the slide to wrap up. As you can see, we continue to check all the boxes, or in this case, the circles, in terms of our high liquids rating, and that puts us in competition with all the top-tier production in the other middle part, middle parts of the Permian Basin and the Midland Basin. We have a prime oil-weighted Permian asset base with high-return well economics, contiguous acreage, which was set up to provide maximum capital efficient long-term development. In fact, our drilling at, down at Signal Peak and in Flattop are providing 15%-20% internal rates of return in the various areas, and these are tremendous returns on the Wolfcamp A and Lower Spraberry zones. We've, we have achieved significant scale at over 50,000 bbl of oil a day, on an economic equivalency basis with our average peers, roughly 80,000 bbl 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 proved development coverage. 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 Spraberry zones at our current 2-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, that these wells are producing the level that they're 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've 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, yet all I will say along those lines is, to me, that is a very dangerous position to be in. 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, you have to make your own decisions. You can see we are definitely on a different page in terms of our management and our, our evaluation of what's happening in the field. Now I'll just... With my comments complete, I'll open it up for questions if, if anybody has any questions. Thank you. Thank you so much, presenters. As a reminder, to ask a question, please press star one, one on your telephone and wait for your name to be announced. Your first question comes from the line of John White of Roth MKM. Please go ahead. I see on slide seven, you've got development drilling focus, will be the Wolfcamp A and the Lower Spraberry. Is that true for Flattop and Signal Peak, or could you, could you talk about what, what formation characteristics may be different between those two areas and the Wolfcamp A and the, and the Lower Spraberry? Yeah, John, I'll have Mike answer 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 Spraberry, both in Flattop and Signal Peak. From an economic standpoint, the A and Lower Spraberry look very similar in both areas. You know, they're almost a lay down economically. So again, it's more fungible as to where we spend the CapEx dollars, whether it's Signal Peak or Flattop. And as you can see, the wells we'll have coming on throughout the rest of this year and kind of development plan for 2024 is to continue, you know, kind of a manufacturing mode method of mowing down the A and Lower Spraberry with 12 years of inventory in just those two zones. You know, earlier when, when it was mentioned, the IRR for these wells, that was actually a net present value, discounted at 10% of about $15 million-$20 million per well. We get our money back that we spent and roughly $20 million a well. Highly economic area, a lot of run room for, you know, the 2 rig program over a decade in just those two primary zones. Again, we're, we're 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 free cash flow. Thanks for that detail, and I'll pass it back to the operator. You bet. Thank you, John. Thank you so much. Our next question comes from the line of Nicholas Pope of Seaport Research. Please go ahead. Nick, you may be... Oh, there we go. Can you hear me? Yes, sir. Hey, I was hoping you guys might talk a little bit about kind of the, the progression of working capital over the near term. I think with everything with the, the equity raise, I think there was some, some current ratio metrics that were, were pushed out, and I think accounts payable and 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, with working capital. Sure, Nick, this is Steve. 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 or positive cash flow, we, you know, anticipate as we move forward, we'll continue it to bring the payables down. That basically is a reflection of the reduced drilling program that we have, going from 5 rigs at the beginning of the year down to 2 rigs and down to also from 4 frack crews to 2 frack 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. Got it. That's helpful. I appreciate it. Got one more here. Just looking at a CapEx for the quarter. I mean, y'all, I think you'll brought online 10 more wells in 2Q relative to 1Q. Similar number of wells drilled, but CapEx was down $80 million. I was hoping maybe you guys could talk a little bit about, you know, well costs and maybe what kinda caused that drop despite the higher level of activity, if that makes sense. You bet, Nick. This is Mike. You know, as we reduce activity, you know, of course, a lot of dollars and a lot of activity has to take place to bring these wells online. In the first quarter, you know, a lot of the work for the wells that come online in the second quarter were done and paid for in the first quarter. That's part of why you see so many wells come on in the second quarter, the cost dramatically different on a per well turned in line basis. When you kinda step back in general and just look at what the OFS pricing is doing, you know, things have leveled off. We're actually seeing kinda single-digit overall reduction in costs from services, mainly driven from fuel, tubular goods. Of course, we're starting to see a little softening on horsepower and rig rates. It's kind of a twofold answer here. As we reduced our rig count and frack spread count, we were also 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. Kinda goes to the same point when you plug in just 1 drilling rig to highline power, that's 50% of our fleet today. We're able to, you know, utilize more of those cost-saving initiatives. What you'll see on a per-foot basis, you'll see that it's gonna 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. Think somewhere in the kind of 4%-5% range is what we're seeing today. Got it. That's very helpful. I'm gonna squeeze one more in, if you let me. Please do. Were there any... I think, kind of over the past year, you've had a number of, kind of one-time impacts from shut-ins or, or frac offsets. Did you see any of that in, in 2Q, or did you all think this was a fairly clean quarter from a production standpoint? Nick, on any 1 day, you know, you always have, whenever you're fracking wells near existing production, you'll have shut-ins. Obviously, going from the 4 frac crews down to 1, you have less shut-in. Again, as we kind of talk through that production profile that you saw on one of the earlier slides, early on, you know, whenever you all said you're only producing three to kinda 20,000 bbl a day, and you have to shut in, you know, 10,000-12,000, it's very impactful. When you're producing over 50,000 bbl a day, and you have to shut in 2,500-3,000, that is always going to kind of follow that frac crew when you're offsetting existing production. To that, I'll 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 kinda look out about two, three months out from adding a lot of rigs, then you would see a little, a little bit more of that water out effect as we were to accelerate in the future. But from here, holding a 2-rig program, this is very ratable, ratable. It'll be up and to the right for growth, as opposed to kind of the sawtooth pattern you saw in the past. Got it. Okay. Well, I think I took plenty of time. I appreciate it, everyone. Thank you. Excellent. Thank you, Nick. Thank you so much. Your next question comes from the line of Jeff Robertson of Water Tower. Please go ahead. 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 type exposition. You bet, Jeff. You know, we've mentioned kind of in the past, our farthest northeast, pad that was drilled in the... This is up in Flattop. Our, it's called the Conrad pad. It's a Wolfcamp A and a Lower Spraberry. Both of those wells kinda HPK'd somewhere close to 1,000 bbl of oil a day, plus associated gas. Again, that was kind of a 7 mi 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, 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 Flattop, Bayswater is an offset operator to us, to the south and to the east. They've drilled some wells right on the very eastern flank of our acreage block, a well going north and a well going south. Both of those wells, again, tested close to 1,000 bbl a day and are still cleaning up because they're pretty recent wells. Again, we feel confident across our entire acreage block in Flattop. Now, if you go down to Signal Peak, about midway through about 65-ish% of the way from west to east in Signal Peak, that's where we have our easternmost A and Lower Spraberry well. For the foreseeable future, all of our A and Lower Spraberry drilling that we plan to do in Signal Peak, will be from about that, you know, three-quarters or two-thirds of the acreage position from west to east, back to the west. 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 Spraberry inventory that is listed, sits within. Again, we feel very confident in that 12-year inventory life of those two zones with a 2-rig program. Thanks, Mike. Hey, you bet, Jeff. Thank you so much, Jeff. There are no questions at this time. This concludes today's conference call. Thank you for participating. You may now disconnect. Have a great day.