Good day, and thank you for standing by. Welcome to the HighPeak Energy 2022 Fourth Quarter Earnings Conference Call. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, the CFO, Steven Tholen. Mr. Tholen, please go ahead.

Thank you. Good morning, everyone, and welcome to HighPeak Energy's Fourth Quarter 2022 Earnings Call. Representing HighPeak today are our 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 March investor presentation and our fourth quarter 2022 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 March investor presentation. I will now turn the call over to our Chairman and CEO, Jack Hightower.

Thanks, Steve, and good morning, ladies and gentlemen. We want to thank you for joining our call today. As we go forward and think about the last year, it's just amazing that we've had such a banner year. I want to emphasize that everyone is aware that we have begun our process for strategic alternatives, and we'll talk a little bit about that today. But I want to point out that we posted great year-end 2022 results. Hopefully, you've had a chance to look at the press release, and you can see that our expectations further substantiate our long-term strategic plan. As I look back on 2022, unquestionably, we've had a banner year. We increased our business in a really responsible and multipronged approach, both through strategic accretive acquisitions and through organic growth. We've moved from 61,000 acres at the end of 2021 to over 112,000 acres today. We grew our acreage position and delineated the majority of our acquired acreage in multiple zones across our entire position. We increased our production, cash flow, and proved reserves over the past 12 months at rates that no one else in the industry has been able to achieve. We did this by maintaining a very healthy balance sheet and improved the productivity of our primary reservoirs as evidenced by our 2022 vintage wells outperforming our 2021 and 2020 well results. We're proud of the fact that we've been able to continue improving through our operational efficiency, learning about how to treat these rocks in terms of completion, larger drilling pads, infilled child locations, and a higher percentage of wells in our Signal Peak area. We maintain our peer-leading margins and actually increased our cash margins throughout last year as our operating teams made significant strides in reducing lease operating expenses and total cash costs. This is tremendous progress that we expect to continue into the future. I'm really proud of our lean organization. Everyone continues to work hard. Their efforts towards cost reduction on both sides of the equation, maximizing capital efficiency, lowering operating expenses, and optimizing well performance make us one of the few teams in the Permian Basin that are actually improving on our well performance. The seamless asset integration allowed the company to accomplish these milestones in 2022. It was a challenging year due to various factors, including serious inflationary pressures and supply chain disruptions, just like the rest of our peers. However, we navigated through these challenges and actually improved. We ended on a high note, and we fully expect this momentum to continue in 2023. We are focused on optimizing shareholder value, our returns, and our accomplishments relative to our business. The first slide I want to talk about is on Page 4 of the deck. Our production averaged 37,300 barrels a day, which is a 42% increase over the third quarter and a 150% increase compared to last year's fourth quarter. That is unprecedented growth. We still have lumpy production; we go up one quarter and maintain the next quarter. We will continue having lumpy production, so don't multiply that 40% increase four quarters in a row. If you think about it, if we hit our guidance, we're going to continue meeting our guidance throughout this year. We exited the year at close to 40,000 barrels a day, which was at the high end of our guidance. We also had somewhere between 1,000 and 2,000 barrels a day during the fourth quarter due to some midstream expansion projects. If it were not for that, we would have surpassed our high end on both our average and exit production guidance ranges. We increased our crude reserves by 92% year-over-year to 123 million barrels of oil. We continue to expand our acreage footprint, now over 112,000 acres, with line-of-sight for additional increases. We're getting good contiguous add-ons as we expand our acreage blocks. We have two contiguous acreage blocks with high working interest. We're set up for long laterals, averaging around 12,000 to 12,500 feet. Our capital efficiency on our development program allows us to hold our entire acreage position with 1 to 1.5 rigs. As you can see, we had several wells in progress at the end of the year that will all come online during the first half of 2023. Presently, we have almost 57 wells that are currently in the process of drilling and completion. Wells that are already drilled and in progress will add significantly to our production going forward. We had several additional wells in progress that will help us substantiate our production guidance numbers. Many of these are in other zones. Looking at financial statistics on this slide, we're projecting to exit the fourth quarter of next year utilizing $90 a barrel, a price that is being utilized by most of our peers for budgeting purposes, although we recognize prices are below that right now. We expect to exit the fourth quarter of 2024 with almost $2 billion in EBITDA, reflecting great improvement as we move forward. The next slide is Slide 5. Our differentiated growth story takes us from overspending to actually having free cash flow in this year's business. I've had people ask me when this will take place, and the answer is we just don’t know because we don’t have a crystal ball as to where oil prices are going to be. However, if the analysts and our internal projections are correct, we will start seeing free cash flow in the second half of next year. We are on course to reach that inflection point with material free cash flow generation.

Thanks, Jack. Now turning to Slide 6, margins. It sounds like a broken record, but our BOEs are not the same as everyone else's. We continue to expand our margins differentially to our peer group. Our fourth quarter margin per BOE was 47% higher than our peer average. This theme will remain over the coming quarters as natural gas prices stay depressed. Don't forget the gas prices in the fourth quarter were higher than what we're seeing today. With our high oil mix, HighPeak's margins will expand even further compared to our peer group next quarter. On a relative value basis, our average peer would need to produce about 60,000 BOEs per day to achieve the same cash flow results that we do with 40,000 BOEs per day. In today's market, a company producing in line with 60,000 barrels a day is typically viewed much differently by Wall Street, but I believe the emphasis should be on efficiently converting oil and gas into dollars and cents, and that is exactly what we focus on at HighPeak. While we are very bullish on oil prices long-term, the short-term price volatility looks like it will continue. We are fortunate to produce such valuable barrels, which will help us remain financially strong even during periods of price volatility. In addition to our BOEs being oil-rich and highly profitable, we continue to drive down our operating costs, which will further increase our core cash cost. Our all-in cash cost per BOE continues to decrease. We reduced our LOE by 15% quarter-over-quarter. Now in the fourth quarter, G&A was a little higher due to year-end bonuses, but it's reasonable to expect that it will continue to drop, as evidenced by our previous quarters. We maintain a lean and efficient workforce as volumes increase. As the denominator grows, fixed costs will continue to be diluted, further expanding our margins. This is a great time to commend our HighPeak organization. 2022, as Jack said, was a great year for our company, and none of this will happen without the effort of our team. We continue to drive operational excellence in all facets of the business. We are removing costly generators, and our fixed costs continue to reduce as our production increases while building infrastructure and Signal Peak, which will further reduce our costs in that area. Our margin per BOE is the best in the business and will continue to expand, further differentiating HighPeak from our peer group. Now turning to Slide 8, ESG. We've been transparent with our goals and initiatives. Fortunately, we were the original architect of our position and were able to set up everything with efficient operations and environmental stewardship in mind. Power: We run a very energy-intensive business, so it's imperative that we are efficient, clean, and scalable. We oversized our substation, allowing another rig or two to utilize high-line power at Flat Top. We've also added another frac crew in fuel. Facilities: We build large-scale central tank batteries that minimize our footprint and make adding additional wells cheaper and more environmentally friendly. Recycle: We continue to recycle high levels of our stimulation fluids and are expanding our recycled capabilities across both large acreage blocks, reducing costs and the need for makeup water. Sand: We now have three frac crews utilizing local wet sand, which greatly reduces our emissions and costs. All of our ESG initiatives are both financially and environmentally rewarding for our shareholders. HighPeak looks at these initiatives as just doing the right thing. Now turn to Slide 9 for the Flat Top operational update. East Howard County has always been plagued by skepticism regarding whether we have good rock and enough inventory in multiple formations. The work we've done demonstrates very robust economic results across the entirety of the block. For bullet #1, we extended the Lower and Wolfcamp A into County, four miles northeast of our main development area for the Wolfcamp A and almost seven miles east of our existing Lower Spraberry wells. Both of these Conrad wells are performing similarly to the development in the core of the Flat Top area, again expanding the footprint for our inventory. For bullet number two, we have a four-well stacked lateral pad with a Wolfcamp D, three-finger tests, and a Wolfcamp B as well as Lower Spraberry and Wolfcamp A. These wells provide multi-zone support for additional inventory in this area. The Griffin pad for bullet #3 is a five-well pad with three Wolfcamp A's and two Lower Spraberry wells, once again solidifying that the Lower Spraberry and Wolfcamp A formations are solid across our entire Borden County acreage. The Southeast Flat Top area, bullet #4, indicated similar well results to those back to the west, reinforcing our confidence in this area. All of these results provide a clear view of the inventory runway and our ability to efficiently grow HighPeak's production. The HighPeak surface for bullet #5 houses our field office, our one million-barrel recycle facility, and is home to the solar farm.

Thanks, Mike. The next slide on Slide 11 provides our year-end proved reserve summary. As I mentioned earlier, we've had phenomenal success over the last two years, as evidenced by a 130% compounded annual growth rate of our proved reserves. Remember, though, that our BOEs are different, currently having 47% higher margins than our peers' reserves. Our reserve replacement ratio in 2022 was 550% through the drill bit, not including acquisitions. When considering our 2022 acquisitions, our replacement ratio then increases to over 750%, unprecedented in my 53 years in the business. Of course, if you didn't have any reserves in the well and it was a discovery, it would lead to tremendous growth. However, now, with over 220 wells drilled to continue this growth process, it's essential to understand the nature of our future expectations. The trajectory of proved reserve growth will continue as we've fully considered the total resource potential for these assets, considering we have over 2,500 locations. We have intentionally been very conservative in our annual reserve booking process. We are not changing anything; we believe in continuing to be conservative, and at 6% of original reserves, we are not booking reserves from one end of the field to the other. We do step-outs conservatively, and we will continue this approach. Keep in mind that any five-year period with outside engineers, it does not matter who they are, you'll find our reserves grow significantly over periods of time with continued technological advancements. Our reserves will continue to rise, our recoveries will continue to rise, and we will also improve return deliveries. We are implementing improvements regarding the turn-on-investment parameters as we progress forward in this business. Therefore, we will adhere to our conservative booking process; however, there's a lot of potential for growth. The next slide compares our area in Eastern Howard County to Western Howard County, where we delve deeper into the basin compared to some of the larger peers in the area. We discussed our rapid growth of reserves; Eastern Howard County is a highly active area, and the margins are indicative of a differentiated performance in the basin. By year's end, our statistics for Eastern compared to Western show our recovery factors are outperforming the West, with results indicating an increase in performance. HighPeak is outperforming its peers in this regard. We now have numerous wells drilled, and our results reflect over 500,000 barrels recoverable compared to 471 of our peers in the West. We are almost 10% higher in EUR and also in economics when assessing our activities, not accounting for having a higher oil cut. Recently, a local newspaper in Midland announced that Howard County is the fastest-growing oil producer in the entire United States, securing the #3 position in the Permian Basin for oil production. Thus, we are in a great area, and these results will continue to improve as we move forward. These positive outcomes reflect our success in Southern Borden County as well. As Mike outlined previously, our delineation of Lower Spraberry and Wolfcamp A in this area will increase additional shareholder value. Our approach is not just about acquiring leases but also strategically expanding our footprint as we continue drilling. Slide 13 provides insights into our inventory, indicating that we have over 1,300 primary locations, which gives us more than 14 years of primary inventory runway. Each time we make a presentation, we have more wells drilled, and we're delineating other zones. Therefore, as you review this chart, you will see our ongoing efforts to develop from Mill Spraberry down to the Wolf B, inclusive of Wolf B three fingers and various other zones. We are actively developing all these zones, and in the next few quarters, we expect to gather more information that will positively impact our overall outlook. We've previously communicated our intention to reduce our rig program from six rigs in the second half of 2022 to four rigs throughout 2023 and 2024. Several factors influenced this decision, not because we lack results from drilling activity, but rather to maintain a strong balance sheet. Oil and gas prices fluctuated during that period, and we anticipate a higher number of wells that we expect to come online this year, as we have 57 wells in progress. This point underlines the reason for the difference in our CapEx budget for 2023 compared to our forecasted CapEx budget for 2024. We want to avoid overdrilling and seek maximum return on investment. This approach is aligned with our planned development of pads and spacing program. Our unit cost per BOE, already competitive with our peers, is expected to continue decreasing, thereby further expanding our peer-leading margins. This was not accidental; this was a deliberate plan pursued throughout our operations to differentiate ourselves from our peers. The key takeaway from this slide is to emphasize our trajectory towards becoming a free cash flow machine. I've had inquiries from investors regarding when this will happen. While I wish I could specify, I am confident this will occur in the second half of the year. Next year, we project our free cash flow to break even, even at $45 oil, which is unprecedented. Most companies struggle to see profit at that oil price. If prices hold around $90 per barrel, we estimate our free cash flow could exceed $1 billion in 2024. This scenario will enable us to completely pay down 100% of our outstanding debt. If we chose to, we could also increase our drilling program should prices remain in the $90 to $100 range. The important point is that we will have ample free cash flow available on our balance sheet, which is positive news for investors. Although I understand Wall Street typically evaluates companies from a quarter-to-quarter viewpoint, we take a longer-term perspective. Additionally, we are constantly monitoring market volatility in commodity prices and service costs, allowing us the flexibility to adapt our drilling program as needed. We can scale our operations up or down according to circumstances, and we do not have long-term contracts that might negatively impact our plans during fluctuating environments characterized by both high interest rates and low oil and gas prices. We will continue to implement our strategic program to drive shareholder value. In closing, the final slide encapsulates our position, emphasizing contiguous acreage inventory, consistent well results, operational and environmental focus, leading margins, free cash flow, and anticipated growth. The value proposition is clear: one should consider the potential of owning HighPeak stock and maintain holdings relative to our pursuit of strategic alternatives. Our expansive contiguous acreage position allows for maximum capital efficiency, and we possess proven rock quality in a scarce inventory. In fact, a recent observation cited by one CEO indicated that the Permian has reached peak production for the next five years. Our inventory is characterized by consistent high-return results across more than 200 wells drilled to date, and our environmentally sound development program is financially rewarding. Our high oil cut and low-cost operations contribute to differentiated peer-leading margins that promise significant free cash flow generation for years to come. Confident in our ability to optimize shareholder value, we will continue our operational focus and implement processes for strategic alternatives.

Our first question will come from John White of ROTH MKM Capital.

Congratulations on some very, very strong results. I want to ensure that I'm reading things right. On the front page of the press release, you say you've extended development potentially to the Lower Spraberry into Borden County based on three Lower Spraberry wells. Are those wells addressed later in the presentation, the Conrad and the Griffin pads?

Yes, John. Mike will elaborate further, but it extends from the western part all the way to the eastern part of the Conrad and Griffin wells. However, Mike can dive deeper into that.

You bet. Yes, John, as we've picked up acreage in Borden County, the operating acreage we acquired encompassed about 6,500 acres, underpinning the Wolfcamp A activity we've seen. We have numerous more brand sticks drilled in that area. The Wolfcamp A is phenomenal. It mirrors our success seen in the Flat Top. As we started developing the Lower Spraberry and observed results in Flat Top, the rock appeared very comparable on this new acreage in Borden. We extended our reach to where you see bullet #3 on the Griffin pad and drilled two Lower Spraberry wells alongside the Wolfcamp A. These two wells look like a clear continuation from the Wolfcamp A in that area. Thus, we are optimistic and added another zone to that entire area. We then moved further out to the Conrad area, about seven miles west or east of the Griffin pad location, and as Jack mentioned, both the Lower Spraberry and Wolfcamp A there are phenomenal, with one well producing over 900 barrels a day and another over 800, which is impressive considering it's still early in the cleanup cycle. So, this gives us confidence that we can infill between the two development areas and effectively add about 75 to 80 wells that we can confidently develop in 2023 and 2024, ensuring efficient and low-cost operations while driving margins.

Looking at Slide 10, all the pink sticks for the Wolfcamp D, it seems your confidence is increasing in developing that zone.

Yes. The pink sticks on Slide 10 represent the lower base Wolfcamp D, which we've drilled across the entire acreage block. We are confident in the results with the lower base and have seen some of our peers to the west and north drill a little shallower in the Wolfcamp B zone, which we refer to as the three fingers. There are three little streams on the log that we've observed appear more brittle, should hold a frack better, with all the geomechanics and geochemistry suggesting that those wells will prove superior to the lower base D. The chart shows where we've conducted three-finger testing. We've fracked some of those wells and expect results to be ready in the next month or month-and-a-half. In the next few quarters, we will provide updates regarding that shallower zone. We have also walked through some Wolfcamp C tests, which are quite similar in nature; one drill is about to come online, and a couple of others are currently being drilled. As we look forward to presenting results for those wells in the coming quarters, we hope to transition those from upside locations into our primary zones, further extending our inventory of high-return opportunities.

Our next question will come from Jeff Robertson of Water Tower Research.

Mike, on Slides 9 and 10, regarding some of the pads you're displaying, are any of those results additive to the inventory counts you show later in the deck? Secondly, are you testing anything over the next couple of months that's not included in the locations displayed on the inventory side?

So, Jeff, all the locations we have are included in our inventory mix as reflected in both the primary and upside locations. As we develop and prove up those zones, we maintain a conservative approach regarding upside zones, maybe overstating their potential initially. Thus, over time, as we develop more areas, the zones we identified previously as upside will likely transition into primary numbers, enhancing that classification. However, in terms of adding to the total of the 2,500 we currently hold, the additions stem primarily from the completion of these wells.

So it's primarily about continued derisking from upside to primary as you move categories.

That's correct. With each step out, we adjust our evaluation of where upside zones may be prospective.

With respect to delineation presented on Slide 12, Jack, you mentioned a 6% recovery factor regarding your reserves. How does that recovery factor on Flat Top and/or Signal Peak compare to the central part or the western part of Howard County?

Jeff, that's a great question. Companies typically use different recovery factors for their reserve bookings. The majors often reference a 6% recovery factor, while many smaller mid-cap companies compare eastern and western figures with about a 2% variance, running from 6% to 8%. In evaluating the performance, the eastern region is outpacing the western area. The typical difference on a macro scale is around 2%, representing about 25% differences between west and east in regards to recovery factor and company size. We expect improvements, and many companies are even using recovery factors reaching up to 14% in our area. However, we prefer to adhere to a conservative approach and utilize factual metrics, allowing flexibility for buyers in terms of reserves while minimizing concerns over revisions or impairments. So as long as we see a consistent increase of 150% annually, that’s our guide moving forward. As we delineate further this year, recovery rates could rise, as we might extend our efforts for PUD development more than originally planned.

That makes sense. Regarding the revisions in this year's reserve report, I believe previously you had indicated a 5 to 6 rig cadence extending beyond 2023. Is part of this year-end reserves revision linked to your 5-year development plan as it aligns with the December report?

Yes. It's quite nominal. The changes stem primarily from adjustments in our drilling plans, with the aim of maximizing shareholder value and ensuring a robust balance sheet.

Last question. If HighPeak chose to engage in more drilling in '23 and '24, maybe more so in '24, and not focus solely on generating free cash flow, do you have an idea of what you could undertake while also managing the existing infrastructure surrounding this acreage space in relation to the number of rigs?

We have enhanced our infrastructure in Flat Top, and we are improving our unit system and tank battery system. Everything was designed with the potential for expansion. Thus, if we decide to return to operating six, seven, or even eight rigs, we can do so without major alterations to our infrastructure. Additional production can be accommodated with common add-ons that would fall within the $20 million to $30 million expenditure range. Our plans are set to facilitate this kind of expansion efficiently going forward.

This strengthens the argument for having contiguous acreage and your established position in these zones, giving you a real infrastructure advantage for future development.

Absolutely, this is a critical aspect of our strategy. Our development initiatives are not focused solely on short-term gains; instead, we aim to sustain long-term viability and attractiveness as an asset for prospective buyers. We ensure they can control their trajectory with high profit margins, as they could allocate more drilling rigs into this area to improve production and maximize returns by targeting their capital investment strategically.

And I am seeing no further questions in the queue. This will conclude today's conference call. Thank you all for participating. You may now disconnect and have a pleasant day. The conference will begin shortly.