Welcome to the HighPeak Energy 2023 First Quarter Earnings Call. At this time, all participants are in listen-only mode. After the speakers' presentation, there will be a Q&A session. Please be advised that today's conference is being recorded. I will now hand it over to Steven Tholen, Chief Financial Officer. Please go ahead.

Good morning, everyone, and welcome to HighPeak Energy's first quarter 2023 earnings call. Representing HighPeak today are Chairman and CEO, Jack Hightower; President, Michael Hollis; and I am Steven Tholen, the Chief Financial Officer. During today's call, we will make reference to our May Investor Presentation, and our first 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 May Investor Presentation. I will now turn the call over to our Chairman and CEO, Jack Hightower.

Thanks, Steve, and good morning, ladies and gentlemen. I'm going to start my prepared remarks on Slide 4 of our May Investor Presentation. This is an important slide. Of course, I have the old adage, you can lead a horse to water, but you can't make him drink. Everything that we're doing, relative to our plan going forward this year and next year, can be summarized on this slide. I know that the market hasn't liked our stock today and our press release, but I believe when I made the statement, you can lead a horse to water, but you can't make them drink. It's really hard for me and for the management team not to be able to buy stock right now at this low price because we're more excited about the company than we have ever been. If we weren't restricted in our ability to buy because of strategic alternatives and because of all the things we have ongoing, we would be buying our stock profusely at the current stock price. Looking at the current economic environment and the volatility of commodity prices so far this year, we are taking proactive steps with our updated '23 development plan to strengthen our financial position and accelerate our transition to positive free cash flow with minimal effect on our growth trajectory. We plan to accomplish this by reducing our rig count from four rigs to two rigs for the remainder of the year. Previously, we reduced the number of frac crews from four to two. This has been our plan all along. You don't plan something like this overnight. It has nothing to do with liquidity or lack thereof. In fact, very shortly, you're going to see that our short-term debt situation will be more than handled. The company could have continued on. And relative to strategic alternatives, unquestionably more production is better. But we have to run the company with the long-term plan in mind with a 50% growth rate this year and another 30% growth rate next year. We still have plenty of growth. We are a growth story. The change will also reduce approximately $250 million from our original capital budget. We will, however, continue to maintain an average of two frac crews for the rest of the year. This will allow us to complete our inventory of operational DUCs that were generated with our prior six-rig program. The two frac crew run rate will enable us to complete and add wells to production typical of a four-rig cadence. The reduction in drilling activity demonstrates our commitment to financial discipline. Nobody knew what was going to happen relative to oil prices. We have a big decline today. We are perhaps going into a recession. So, our attitude is to under-promise, over-perform, and be careful going forward. Relative to financial discipline, doing this allows us to stay well below our one-time maximum leverage range, which has always been our philosophy. For 53 years, we've never wanted to get out over our skis; it's why we've never had any losses on any transaction in that time. As a result of this new plan, we're now projected to reach positive free cash flow in the third quarter at current commodity prices. It's a testament to the high quality of our asset base that allows us to slow down our development cadence for the remainder of the year while keeping our production guidance very close to our initial range, approximately doubling last year's production. We plan to increase to a four-rig program in early 2024, and we anticipate funding this entirely through operating cash flow. This will allow us to simultaneously increase our production year-over-year by more than 30%. As you can see from the Slide, the '24 free cash flow sensitivity chart at the bottom, under our four-rig program, we're projected to produce a large amount of free cash flow under any reasonable oil and gas price scenario next year. Generating significant free cash flow will provide us with a lot of optionality: we can use the cash flow to pay down debt, we can increase returns to shareholders, or we can further accelerate our development program. We are going to remain focused on our long-term development strategy to maximize value for our shareholders either through sustained operations or our strategic alternatives, and we believe this plan will accomplish that objective. Now turning to Slide 5, this is a slide that you've seen many times showing our contiguous acreage position. Our first quarter production averaged 37,000 barrels a day, which is about even with our fourth quarter average. If you recall, our historic plateau growth pattern provides for flat growth one quarter, followed by a large jump the next quarter. This is going to continue as we go forward. I'd like to point out that our first quarter average was an increase of over 200% year-over-year compared to the first quarter 2022. We continue to be a growth story. As of quarter-end, we had another 64 wells in various stages of drilling and completion. Under our revised plan, we expect to turn in line 110 wells this year. This will allow us, and going back to the first slide, what our production numbers and guidance are showing. As shown in the operating statistics, we project '23 high of 50,000 barrels of oil a day range and in '24, an exit of over 70,000 barrels a day. On any reasonable metrics that you're looking at as a multiple of cash flow, considering the number of locations that we have, which shows over 2,500 in this slide, and that's a conservative estimate on the number of locations that are commercially viable for this company. That's still great growth and great exit potential relative to strategic alternatives. Now turning to Slide 6. This is also an important slide relative to our differentiated growth story, which will continue while simultaneously transitioning to free cash flow. We feel that it's important as we start reaching more of a plateau in production growth to maintain free cash flow and not to get out over our skis with too much debt in this environment. We have grown our production base to 40,000 barrels a day over the last few years while maintaining a conservative balance sheet. That philosophy is going to continue. There is no better way to prove high rock quality than by exhibiting substantial production growth through the drill bit. As shown in this slide, by executing our business plan, we will have an EBITDA run rate of about $1.2 billion at a flat $80 price deck. You can see how that goes up with higher prices. In addition, we will be positioned to continue increasing our production next year at four rigs, funded 100% from cash flow from operations; that's not something many companies in growth mode can do. Now turning to Slide 7. This is perhaps one of the most important slides. We've talked about our operating margins, and we continue both historically and this year and into the future to have the highest margins among our Permian peers. Our first quarter margin per BOE was 55% higher than our peer average. This theme will remain over the coming quarters as natural gas prices stay depressed. Higher margins give HighPeak cash flow generating capacity at much higher equivalent production volumes. In the first quarter, HighPeak's 37,000 barrel a day average would have been equivalent to almost 58,000 barrels a day based on our peers. That's important relative to our pricing, and important relative to strategic alternatives that we literally at year-end will have almost 90,000 barrels comparing to 60,000 barrels produced by others to get that same cash flow and value. Our high oil cut, low production operations, and low-cost operations increasing production will continue to differentiate our barrels of oil equivalents relative to our peers. Mike, I'm going to now turn the call over to you for an operational update.

You bet. Thanks, Jack. Now turning to Slide 8. HighPeak continues to demonstrate improving well results across our acreage position. We have more than doubled our footprint over the last few years, and during that time, we have delineated geographically and stratigraphically across several different zones. Our blended results continue to improve. This gives us confidence in our substantial inventory, and we will be able to increase production and generate significant free cash flow for the foreseeable future. The chart on the right of this slide shows all of the wells that we have produced and their performance over the last three years. Our 2022 vintage wells are outperforming our previous years. This includes drilling larger pads, infill locations, higher percentage of Signal Peak wells, and wells in multiple benches. HighPeak's inventory averages 12,000-foot laterals, and we've spaced our locations very conservatively, leading to increased capital efficiency and maximum well performance, which also leads to higher free cash flow generation and value creation now. There have been some reports put out recently regarding HighPeak, and there are a few key things to consider when evaluating publicly available data. Public data does not take into account the shut-in days when producing wells are temporarily shut in for offset frac operations. HighPeak has been very active in and amongst our producing areas. Additionally, our wells take between 45 and 60 days on average to ramp to peak oil production, which is a longer timeframe than most wells located further to the west. This affects any direct comparison focused on the available short-term data. Our wells don't decline as fast as our peers located to the west either, allowing HighPeak to efficiently grow and layer in new production. Another important note when comparing our wells to those of our peers is that HighPeak's capital cost to drill and complete wells are lower. Our area is a little shallower than that to the west, and the contiguous nature of our acreage position, which we have set up to exploit with maximum capital efficiency, allows us to drill our wells at a cheaper cost per completed lateral foot than the majority of our competitors. So, when you take all those things into account, our wells absolutely compete for capital and provide rates of return and breakeven costs that are competitive with our peer group. Now let me talk about how our well performance has continued to improve over the last three years. Let's focus on the Flat Top area. So, turning to Slide 9, I'd like to point out the red dotted boxes on the map. These areas highlight where most of our Flat Top development activity took place during the first quarter. As you can see, these were where we already had a significant amount of existing production. We had a lot of temporary curtailments due to offset frac operations that impacted our Q1 production. The Conrad pad, bullet number one, extended the Lower Spraberry and Wolfcamp A into Borden County. That's four miles northeast of our main development area for the Wolfcamp A and almost seven miles east of our existing Lower Spraberry wells. Both Conrad wells continue to perform similarly to the wells in the core Flat Top area and give us confidence to expand our development program. Bullets four and five highlight a few areas where we now have Wolfcamp A and Lower Spraberry co-development planned later this year based on the performance from our initial delineation pads. Bullet six highlights a two-well Wolfcamp A pad that was drilled by one of our offset operators, which now confirms the Wolfcamp A potential further east of our acreage position into Mitchell County. All of these results provide a clear view of our inventory runway and our ability to continue to efficiently grow production. Now turning to Slide 10, Signal Peak. HighPeak has been very active in Signal Peak since the acquisition closed last year. As you can see, all of the locations highlighted in pink are base lower Wolfcamp D wells. We now have 26 producing, and the results have been very consistent across the entire block. Historically, we focused on the Wolfcamp D due to the capabilities of the existing infrastructure. Now that we have upgraded and built out the required infrastructure, we are now focusing on the Wolfcamp A and Lower Spraberry formations, which are cheaper to drill and yield higher production, equating to much higher returns. We have continued to delineate these zones, as shown by bullets one and two. Based on those results, we are now proceeding with initial Wolfcamp A and Lower Spraberry multi-well pad development as shown by bullets three and four. These pads will be coming online over the next few months and will help support our production growth this year. The Wolfcamp A and Lower Spraberry wells in Signal Peak have similar rates of return and performance as Flat Top in these formations. Our current plan is to focus more on these zones for the next several years, which will increase our capital efficiency. Bullets five through eight show where we were testing a different landing zone within the Wolfcamp D formation, referred to as the 3-Fingers. This landing target is roughly 150-feet shallower than our previous Wolfcamp D targets. Some of these wells were recently turned online, and we expect to have a good sense of the results in the coming months. After we verify these results, the 3-Fingers Wolfcamp D wells may compete for capital in 2024. We are still expanding our recycling capabilities and overhead electric power systems, which will continue to drive costs down. We turn now to Slide 11, ESG. ESG is woven into everything we do at HighPeak. Power: We run a very energy-intensive business, so it's imperative that we be efficient, clean, and scalable. We oversized our substation which allows for rigs to utilize high line power, and we expect to energize our solar farm in the fourth quarter. Facilities: We build large-scale, central tank batteries that minimize our footprint and enable adding additional wells cheaper and more environmentally friendly to connect. Recycle: We continue to recycle high volumes of our stimulation fluids and are expanding our capabilities across both of our large acreage blocks, reducing cost and the need for make-up water. Sand: We continue to service our two frac crews with local wet sand, which greatly reduces our emissions and costs. HighPeak views these initiatives as just the right thing to do. Now turning to Slide 12. This slide provides a snapshot of the systems that we just discussed. As you can see on the maps, we have prepared this asset for full efficient development by building out the infrastructure needed. Most of the money for these scalable systems has already been spent. This build-out allows HighPeak to lower our OpEx, lower our CapEx, and receive the best realized price for our product. The photo represents our central tank batteries that are scalable, efficient, and environmentally friendly. With my comments now complete, I'll hand the call back over to Jack.

Thanks, Mike. If you'll turn to Slide 13, we always continue, as we develop our drilling program, to compare our wells on the eastern side of Howard County to the western side of Howard County. As you know, Howard County has now become the third largest producing county in the Midland Basin and one of the fastest growing counties for oil and gas production in the entire United States. The perception used to be that the wells to the west and the deeper part of the basin were going to be more prolific, have higher EURs, and better economics. As we move to the east though, we are finding out on a comparative analysis that the recent results show that the eastern area of the county is actually outperforming the west on a barrel of oil per foot basis. In the last two years, more wells have been drilled in the east half versus the west. Furthermore, HighPeak is outperforming its peers in the eastern part of the county. All of these factors confirm that Howard County is an area in the Midland Basin that will continue to provide strong shareholder returns. Another point I would mention about Howard County and our acreage position is that we now have differentiated from the north to the south at Flat Top and from the west to the east at Flat Top. We know our assets well. We have multiple zones that are going to be commercial in that area, and we're extremely excited about that. We know, down south at Signal Peak, the economic returns in the Wolf D are not quite as high, but they're still very commercial and positive. We have wells north, west, east, and south, all with complete delineation of the Wolfcamp D, and we know that the 3-Fingers looks to perform better than the basic Wolfcamp D. Additionally, half of our acreage position to the south looks promising in the Wolf A and the Lower Sprayberry as Mike mentioned. Now, turning to the next slide, we have operational scale and we're going to continue growing. Even though we had 200% growth in the first quarter year-over-year production, it's going to continue growing at least 50% from where we are this year and up another 30% next year. Importantly, this 2,500 gross locations is not speculation. Pulling back on our drilling program wasn't done due to lack of confidence in our inventory; rather, we had better confidence as our wells are performing better, as Mike mentioned in the operational presentation. We have a 14-year primary inventory life at a four-rig cadence. So we're going to be able to achieve high production and maintain positive cash flow. We still continue to maintain peer-leading margins and a cost structure among public companies that is superior. Our inventory is highly oil-weighted, with 85% of production being oil and 94% liquids. This trend will continue because of our geographical area and the oil cut we have in that region. Importantly, we are entering an era of free cash flow in the second half of this year, which will allow us to maintain a low debt-to-equity ratio as we move forward. We are doing everything within the framework of cash flow, and we will still continue to grow the company. There aren't many young companies like ours that have this opportunity. So, with that, there's not really anything left to say. I’d like to open up the call for questions.

Thank you. At this time, we will conduct a Q&A session. Our first question comes from Jeff Robertson from Water Tower Research. Please go ahead.

Thank you. Good morning. Jack, you mentioned the notes which mature; the first tranche of notes matures in February of 2024 and the second, I believe, in November of 2024. Can you talk about how you're thinking about those notes?

Yeah, Jeff. I know everybody is worried about that because basically relative to the current ratio, those first notes are due but we still have plenty of time on it. We have no pressure at all from the banks regarding the notes. They've waived those requirements. We could also extend those notes or take other actions to address that situation by converting to longer-term debt. As I mentioned, we have a plan in place, and we'll be announcing something very shortly that addresses any perceived liquidity issue that shareholders might have. That's going to be taken care of. We had the plan in place for quite some time, and we'll be executing that plan within the next few weeks.

On March 15, the borrowing base under the RBL was increased to $700 million from $575 million?

Yes.

When does the next redetermination that will reflect the development activity that you all have underway in 2023?

We're in the process now of doing a re-determination on that borrowing base, and we expect the borrowing base to increase and the commitments to also increase from $575 million where we are today. So, again, that's not going to be an issue.

And then a question, Mike, on Slide 8 where you talk about improving well performance. Can you talk about why the curves start to diverge after roughly 180 days?

Again, Jeff, with the way these wells typically produce, they don't free flow for very long. We frac them, then we put ESPs in the ground. They're all going to look fairly similar the first few months of our production. That's part of why they all line up since the performance is pretty similar. Later on, when you start seeing more contribution from a larger stimulated rock volume, you start to see that in the latter parts of the year. So that's what you're seeing; we're getting more effective drainage and you're starting to see that. Early on, it's hard to see because you're pump limited.

Okay. Lastly, Mike, I believe you included about $1.25 per barrel of oil equivalent in lease operating expense for the first quarter of 2023. Can you discuss the main components of that? Additionally, how do you expect lease operating expenses to trend for the remainder of this year?

You bet, Jeff. So, the $1.26 or so that you're referring to on the workover expense relates to our fracking operations with three frac crews up in Flat Top. We were utilizing a large amount of our produced fluid, which allowed us to conduct repairs to a couple of our SWDs up in Flat Top that we had been waiting for the right time to do. So, about three quarters of that $1.26 was just those SWD repairs. Now that they're complete and we're reducing activity, the SWDs are available for us to utilize which keeps our costs and OpEx low. As we go forward, beginning with the first quarter, we brought on several new wells. Production typically takes a month and a half to two months to reach peak oil production. Thus, when you turn on a larger number of these wells, you incur costs associated with lifting that fluid and yet have very few BOEs to divide that cost by at that time. Therefore, you can expect our trends throughout the rest of this year to go downwards. We have also removed several generators with our overhead electric build-out. New acreage had required the use of several generators initially to ensure continuity until the overhead power was installed to those new tank batteries and facilities. Thus, you can expect LOE trends to decrease substantially moving forward, and we've guided as such.

Great, thank you.

You bet. Thank you.

Thank you, Jeff. One moment for our next question. Our next question comes from Nicholas Pope from Seaport Research. Please go ahead.

Good morning, everyone.

Good morning.

Good morning.

Hope we could talk a little bit about field-level production. As you look at the first quarter, I was curious if you have a sense or maybe an estimate on the 32 wells that were brought online; how much did that impact the base of production in the first quarter relative to what you saw in the fourth quarter? And as you see a little bit of pullback in activity for the remainder of the year, how do you think about the shut-in production offsetting completions?

You bet, Nick. That's a couple of questions embedded there. I'll try to address each one. In Q1, you nailed it; roughly 20 producing wells were taken offline for us to be able to frac the activity shown on that Flat Top slide featuring the red dotted boxes. So that amount of production was offline. We have now brought on the 20 or so wells that were turned off and are bringing online all of those wells that we completed throughout the first quarter. In Q2 and Q3, you're going to see significant growth from all of that activity we did in Q1. Remember, we were running six rigs, and had four frac crews. Now, we are level loaded with two frac crews for the remainder of the year into 2024, which is about a four-rig cadence. Since we had drilled with six rigs previously, we will be able to keep the run rate of those two frac crews throughout the year. Into 2024, we will have to step back up to four drilling rigs to continue supporting the two frac crews. In regard to water-out effect, it will certainly be less because of reduced activity, but also, because of the way we’ve got Flat Top and Signal Peak laid out, the activity won’t be bookended by production on both sides too much. The majority will just have production on one side, thereby reducing the water-out impact. So, I think you will see, throughout the rest of this year and potentially into 2024, a smaller total amount of oil being taken offline during these completions but a smaller percentage as our production base continues to grow significantly.

Thanks, Mike. That's really helpful. How do you quantify that internally? As you think about quarter-to-quarter growth, how do you think about quantifying what you expect to be shut-in on a volume basis over the past few quarters? Or is that not how you think about it?

Well, we certainly do think about it. Since I am responsible for allocating capital, there’s a lot of pressure to hit our numbers. When you're growing like we are, if you have any issue at all on a multi-well pad, you're left managing the timing to bring them back online. The geological formations and their performance aren't a concern, it’s purely timing. You experience supply chain and other issues, but overall, you're moving quickly into infrastructure, and with this growth, timing can sometimes be rapid, and other times, a bit longer, which is why we have what I call plateau or platform development. This is where some production remains steady for a couple of quarters before experiencing significant increases. As Mike mentioned, 20 of our wells were offline, and we expect production to continue increasing as we bring those back online, which is already being reflected in our first quarter exit production numbers.

Nick, just to further expand on that, we analyze our model carefully. When we complete a pad, we carefully turn off the offset wells and even adjust a little further out to account for potential water impacts. Timing holds a big part of it. We try to be conservative in how we estimate the timing of bringing those wells back online and when they would reach their expected contributions. This is all incorporated in the model and what we project throughout the year.

Got it. That's very helpful. Finally, in regard to the planned wells brought online for the remainder of the year, is that reasonably steady across each quarter? How do I estimate how many of the newer wells you plan to bring online?

Nick, you're pretty much spot on. It will be a little higher in Q1, but considering we plan to turn in line 110 wells this year and we brought online around 25 in the first quarter, you can expect a bit more in Q2. However, it'll change gradually over the rest of the year to achieve that 110 number. Since we plan to keep two frac crews running, 2024 looks similar to 2023 in terms of total wells as well.

Got it. All right, I’ll let you guys go. I appreciate the time.

Nick, one other thing I want to add is that with the guidance we have, we've really sharpened our pencils and put risk profiles in. We feel confident in under-promising and over-performing in terms of the guidance that you see for '23 and '24 on the first slide.

I appreciate that. Thank you.

Thank you, Nick.

Thank you all for your participation in today's conference. This does conclude the program. You may now disconnect. Have a good day.