HighPeak Energy, Inc. Q1 FY2021 Earnings Call

Thank you for standing by and welcome to the HighPeak Energy First Quarter 2021 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. As a reminder, today's program may be recorded. I would now like to introduce your host for today's program, Steven Tholen, Chief Financial Officer, please go ahead, sir.

Good morning everyone and welcome to HighPeak Energy's first quarter 2021 conference call. Representing HighPeak today are Chairman and CEO, Jack Hightower; and President, Michael Hollis. During today's call, we will make reference to our May Investor Presentation and our first quarter 2021 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, which was issued on Monday afternoon. Our prepared remarks will begin on Slide four of our May Investor Presentation. I will now turn the call over to our Chairman and CEO, Jack Hightower.

Thank you, Steve, and I want to welcome each and every one of you this morning to our call. Our first quarter of 2021 operations went smoothly even in light of the fact that we had Winter Storm Uri. We are continuing to build upon and improve our peer-leading capital efficiency metrics. We are definitely a growth story. And as I go through the presentation on the website, if you – those of you who have access to it, turn to Page 4, but the one biggest important factor there is the fact that we had 150% growth from the end of the first quarter through the middle of May and that's unprecedented relative to a growth story. We are extremely excited. We have a significant all-weighted growth story and we are creating value very, very quickly with efficient operations. We're focused on fiscally responsible production growth and high operating margins. In the first half of May, as I mentioned, we're up to 8,300 barrels a day now with a 90% oil cut. So our growth is continuing. That 8,300 barrels a day represents approximately 28 wells that are producing, and we have 11 additional wells with another well drilling that will add to that growth story as we get these wells online; most of them have been completed, but we are continuing that program. What allows that is we have a continuous acreage position. Of course, management's expertise contributes to our peer-leading costs and full cycle economics, and our EBITDA margins are over $41 a barrel at current commodity prices, which is either the leading or second-leading best returns in the industry. We definitely have a differentiated financial strategy. We're committed to low leverage, and currently have no debt. Recently, we had just approximately 2,500 barrels a day of oil for one year at a price of $61.40 a barrel. That's in keeping with our conservative nature to keep a strong balance sheet. If you turn to Slide 5, we generated a profit and over $20 million of EBITDAX in the first quarter, which on a comparative basis is very, very successful. Our average production in the quarter was almost 5,300 barrels a day. We have zero debt and $9.6 million cash on hand. We've also completed the first phase of our company-owned water system, which is now fully operational. That's going to continue leading the ability for us to lower our lease operating expenses as we go forward. So we are continuing our guidance with a one-rig program, and we've been able, as you can see, to have tremendous production growth, and we are on track to exit the year at 10,500 to 12,000 Boe a day. We are achieving significant production in reserve growth while maintaining a conservative balance sheet, and we're going to continue focusing on low-cost operations, peer-leading capital efficiency while we sustain our leading EBITDAX margins driven by high oil cuts and a low-cost structure. We will continue implementation of our ESG program. On Slide 6, the most important thing here is that in every case it's zero debt, but we've increased production almost 150% in five months. That's unprecedented in the industry. And we've been able to do that while drilling these additional wells and still maintaining our low-cost structure, which Michael will go over later when we get into the operational overview. Our EBITDAX has gone up 187%, but as you start looking forward and projecting that EBITDAX, we're well over $200 million on an annual basis with where we're going to exit the year. We also continued, as you recall, the investor presentation from our last presentation, we were averaging about 9,300 feet per lateral foot drilled. We're now up almost 64% and averaging approximately 14,000 feet while maintaining our oil mix of 90% oil. So it's been very effective in terms of our drilling as costs are going up; we've been able to still maintain our capital efficiency and maintain our cost to drill, complete, equip, and put facilities in place on the wells. Turning to Slide 7, this also contributes to our operational efficiency. We lowered our lease operating expenses by 28%, which will continue to happen as our production increases and as these facilities and infrastructure we've put in place become more effective as we continue our growth story. Our cash G&A went down almost 42%. Again, that will continue to happen as we improve and continue our production. Our operating margin went up over 44%, so that's really unprecedented that we've been able to do that. We have a cash margin of $42.14 per Boe, which is one of the highest in the industry and realized pricing of $54 per Boe. So we're extremely excited about what we've been able to accomplish by drilling over 84,000 feet with one rig, six wells drilled, completed, equipped, and financed – and facilities in place 14,000 feet of average lateral length as opposed to 9,300 in the first quarter, all while maintaining $505 a foot for our drilling costs. And you all know we have some inflation taking place in all costs; every single area from drilling rigs to completion to sand, to pipe, everything is going up and yet we've still been able to continue the efficiency at the $505 a foot cost. So with that basic update, I'm going to turn the presentation over to Mike Hollis, our President, to talk about operations.

Thanks, Jack. I'd like to take this chance to thank all of the HighPeak employees, our service providers, as well as our business partners for the exceptional job that these folks handled during Winter Storm Uri, the pandemic for the last year, and just the monumental performance that we've had with such a lean and effective workforce. As Jack mentioned, we are one of the few growth stories out there. We've had growth of 150% from the fourth quarter of 2020 and we've done that with zero debt. Jack mentioned, we're planning on running one rig. We've drilled and completed six wells, as mentioned with a lateral length of 14,000 feet in Q1. The machine's not going to slow down; we've got more to come. We've got eight wells that are in flowback, four being completed and two in the drilling phase. Jack mentioned we have our Phase 1 water system fully operational and plan to recycle very soon. We've also got the basin's first high-volume horizontal deep Ellenburger SWD, and in our Southern acreage block at Signal Peak, we've drilled the Wolfcamp D and Wolfcamp C wells, which are online, flowing back, and cleaning up. The Wolfcamp D well is flowing naturally and has been the quickest to cut oil of any well we have in our company so far. We're extremely excited about these wells and the drilling potential of these two zones in Signal Peak. Again, these can greatly increase our inventory in our Southern acreage. As Jack mentioned, despite these recent inflationary pressures, our capital efficiency has been rock solid and continues to be peer-leading. If you turn to Slide 9, we'll walk you through our peer-leading capital efficiency and margins. Post IPO or business combination, our capital efficiency has continued to improve and been significantly less than where we were pre-combination. Our current all-in drilling completion, equipping, and facilitating these wells at $505 a foot is best-in-class. Since IPO we've increased our lateral length dramatically and continue to reduce the number of days to drill to TD. For comparison sake, to many of our peers, our current drilling and completion cost is $400 per foot. To help explain why our margins are so differential to our peers, we have to start with high peaks. Our BOE unit of measure is differential to our peers. By that, I mean, our oil cut is significantly different. We have a 90% oil cut today, but the difference between our area in Eastern Howard County and the rest of the Midland basin is the life of these wells; our oil cut is 84%. With natural gas liquids, we are 95% liquids for the life of these wells. Oil and liquids drive your revenue. With a unit of measure that has a higher revenue per unit and with our costs continuing to come down—again, our cash cost LOE down 28% quarter-over-quarter, G&A down 42% quarter-over-quarter—higher oil cut costs that continue to decrease, equal that best-in-class cash margin. Cash margin this quarter is $42.14 per BOE. If you turn to Slide 10, these best-in-class execution metrics, low cost, and high oil cut generate phenomenal returns. A 10,000-foot Wolfcamp A well at $65 oil generates roughly 200% IRR. Our average lateral length for the year is closer to 12,500 feet; that extra footage will increase single well economics and IRR by roughly 30%, again yielding peer-leading returns. The net present value of one of these 12,500-foot Wolfcamp A wells is approaching $14 million per well. Our low cost and well performance drive capital efficient growth in production, value, and reserves. If you turn to Slide 11, I'll give you a midstream and marketing update. The team has been exceptionally busy this quarter, and I want to give thanks to our midstream partners, both on the gas and oil side. A lot of midnight oil has been burnt this quarter. We signed a new long-term crude oil gathering and marketing agreement, and in that agreement, the gatherer will install our system up in Flattop, which is extremely important because HighPeak, 97% of our revenue is attributed to oil sales, and this new system will improve our realized price as we move from trucks to pipe. We've also assigned a long-term natural gas gathering and processing agreement to expand our gas gathering system in Flattop to meet our development plans. This system will be a low-pressure system, which will eliminate the need for in-fuel compression, as well as the emissions associated with that. It will reduce downtime and flaring. Our Phase 1 of our SWD water system is fully operational in Q1. It provides a cost-efficient disposal system for all of our produced fluids and also gives us the ability to recycle that stimulation fluid. Phase two is currently being constructed in the Southern area of Flat Top. We've attacked both sides of the margin equation—higher realized prices, lower operating costs. That's how HighPeak will continue to deliver this peer-leading margin in the future. If you turn to Slide 12, I'll give you our ESG highlights. In January, we established our ESG committee at the board level. Our SWD system has allowed us to remove 11,500 trucks from our Flat Top area in Q1. To date, we've almost doubled that number of trucks off the road, reducing emissions and surface disturbance. We've also signed a preliminary contract to build a new electrical substation and wire upgrade, as well as currently evaluating the use of renewable energy sources for our field operations. To date, we've had zero safety incidents. We've also had zero regulatory violations. HighPeak is active in our local community and continues to provide our employees with flexibility to work from home, as well as from the office in this post-COVID environment. Again, I couldn't be more proud of what our organization has accomplished in such a short order, and I absolutely believe that we're just getting started here at HighPeak. We'll have several more exciting developments that we can disclose in the future. With that, I'll turn the call back over to Jack.

Thanks Mike. I want to reiterate how proud I am of our team, and we have a lean team. We are very efficient from a G&A perspective, not necessarily on a per BOE basis because we're just getting started, but in terms of overall costs to our investors, we have the lowest costs for our overall G&A of any public company that I'm aware of. So we're going to continue that program and make sure we give you all the opportunity in the world to have the best return on investment. As you can see in looking at Slide 13, 150% growth, a very responsible, strong balance sheet with zero debt, and an undrawn revolver, which gives us access to additional capital that we need in our operations as we continue our program, and the ability to increase our growing program as we go forward and de-risk our area. We have great operational success and capital efficiency, and I think the bottom line is on our operating profit margin as Mike discussed, we literally have the highest profit margin of any company in terms of operating profit margins of any public company. We don't know about the private companies, but that's very successful, and one thing that drives that is our 90% oil cut, but also this experienced team contributes to that profitability in addition to that. Mike mentioned our new wells down South at Signal Peak; I'm not going to spend a lot of time on that, but one unusual feature of our wells is after five days, we have almost a 17% oil cut, and to my knowledge, I know it's the best way we have, but it's one of the very best wells in the basin. So we're extremely excited about that and geologically cover our entire acreage position. So we're very, very excited about that. Our first quarter was a tremendous success. Positive earnings, significantly increased production, increased EBITDAX, lower cash costs, and we are currently debt-free. I'm proud of our lean organization and the success we've had. Within the context of every company in my 50-plus years in business, tremendous success also has a very successful investor base, an investor base that recognizes the importance of initially paying a little bit more for stock value and having a company that can utilize all the efficiencies of their currency and their value stream. You saw where I bought almost $2 million more stock last time, and we really need, even though we need float, we need you to invest more dollars if you see fit and to tell your friends, because we need flow. We don't mind having an offering as long as it's not too diluted for us, and presently our stock price is below what our peers are trading at on a multiple of what we project our EBITDA to be. We feel like we have a lot of movement and a lot of upside, and we're tremendously excited about what we've accomplished. Everything from a production perspective is exceeding our expectations. So with that, I'll open the call up for any questions.

Our first question comes from Jeff Robertson from Water Tower Research. Please go ahead with your question.

Thank you. Good morning. Jack, can you talk a little bit about consolidation opportunities in Howard County and, given you're still relatively early stage at both Flat Top and Signal Peak, how that might fit into your business model?

Yes. Jeff, that's a great question. Historically, with the 139 companies we've run, we've basically been balanced with growth through the drill bit as well as consolidation. We have such a large inventory and such an ability to grow our present company that we're going to be a lot more selective on consolidation, ensuring that anything we consolidated with would be accretive to us and is as good as the asset we have. We are looking at lots of opportunities in our area. We're not at all restricted from having good accretive opportunities in our area, both adjacent to our acreage down South and up North, and also moving out from East to West in Howard County. A lot of the companies are over-levered and are having a hard time developing. So we're continuing to look at and evaluate and work on consolidation; as you know our history, even back at Lehman Brothers, we did not engage in transactions in two years. We'll be very thoughtful in our approach, and we'll be very restrictive in the sense that it has to be as good as what we have.

Thanks. Mike, a question on LOE, you all made significant progress in the quarter compared to the fourth quarter. Can you talk about the drivers of that and what you see over the balance of 2021?

Absolutely, Jeff. There are a lot of factors at play, and we're addressing every one of them. Our water system is huge. Again, we've taken a lot of water off of trucks, moving from third-party SWDs to our company-owned SWD that is very efficient to operate. Getting some of these ESPs on electricity and off generators is a big job and project that we have throughout this year. As we've mentioned in the presentation, we've signed a preliminary contract to upgrade the electrical system in Flat Top, which will come in over time. Once we get the substation built, you will see dramatically lower LOE as we start to remove some of the generators that are still in place. So again, we're trying to hit everything from both angles on the margin equation. We want to reduce our cost, and we not only try to address it from the unit cost of lifting and disposing fluids but also to minimize downtime from electrical issues and our lifting equipment. Knock on wood, to date, we have had zero ESP failures. The team in Midland has done a fantastic job operating this equipment. Some of these failures can cost roughly a quarter million dollars every time we have to replace one of these ESPs, so having zero failures to date goes into the calculation for reducing that LOE. The new wells with their high rates and low lifting costs also help us average down that number. We'll continue to build out our oil gathering system and have lag units in place, which will increase production because we'll have less downtime. Everything will become more efficient over the next six months as we continue to implement our processes. So, again, great question. We're attacking every angle we can from both the cost and realized price equations.

Thanks. Lastly, at Signal Peak, it's clearly quite early with these first two wells, but can you talk about any plans you might have there for later in 2021 for additional wells? Secondly, are there any infrastructure issues down there that you have to deal with if you become more aggressive with your drilling there?

So early time infrastructure is in place; there was the old Wolfcamp C gas field there, so there is existing infrastructure for gas and oil takeaway. Early time wells will mostly be trucked. The development plan; we've got locations mapped out across the entire Signal Peak as well as how we would lay out our infrastructure. Once these wells come online and we go to full development, we will also have to upgrade the gathering systems in Signal Peak, along with the power infrastructure in a year or two out. Again, this is different than back in the '70s and '60s. We require a lot more power and generate a lot more oil and gas than what was done in the past. So, yes, we would need to upgrade those systems in the future, but early time, everything is in place and ready to go.

Right. Thank you very much.

You bet.

Thank you. Our next question comes from Carter Dunlap with DEM. Please go ahead with your question.

I'm sorry. Is that better?

Yes. There we go.

Pardon me. Hi, guys. You've included in the deck in the appendix three slides, 17, 18, and 19 but not spoken to them. What is the takeaway from those, I mean, for the layman on the call, including me?

Well, Carter, basically, if you know the growth of Howard County back in 2016, we just had a hundred and something wells drilled in the western part of the County. The industry has moved from west to east, and there was a mentality that as you move closer to the shelf edge of the basin on the eastern side, you're moving up dip. You definitely have more carbonates. You're going to have more water, which you naturally have with carbonates, but people didn't realize that the zone itself was there, and it was almost as thick and as profitable as we moved from Slide 17 over. You can see our zone of production is just as thick and just as profitable, and it's going to recover just as much oil. We increased the carbonate side, which gets into Slide 18. With that carbonate, one limestone, 52% of all the oil that's been produced in the Permian Basin came from the carbonates. The historical thought geologically was that these are dense limestones with no oil present or organic characteristics that would hinder oil production from that formation. We've worked in the area since 1978 and we knew that this wasn't a typical limestone. In fact, when you look at it just coming out of the sample, it's totally black. It's organic and has a high level of kerogens, which means it actually generates oil from the carbonate. So, we have almost two reservoirs inside one reservoir in our area, which leads to not being on the treadmill is bad, not having as high of the decline curve, and having more oil in place. Slide 19 displays our inventory, which emphasizes why we are selective in terms of consolidation because we can build a very large company by just developing what we already know. We didn't assign any value to the Wolfcamp C or in the Wolfcamp D, even though we knew the possibilities existed for those zones, which is proving itself now down at Signal Peak with our new wells. The data indicates that we have a vast inventory, a decade of inventory, and geologically and geophysically, our area is flush with oil in place. This gets into underlying oil in place numbers, and we're looking at 30-40 million barrels in place per section for Wolf A and Spraberry, and 35-40 million up to 50 million barrels in the D and Wolfcamp C, showcasing a lot of potential throughout our areas up north and south.

That was about as robust of an answer as I could have expected. I'll have to listen to the replay to make sure I sort it all, but thank you very much.

Okay, thank you.

Thank you.

Thank you. This does conclude the question-and-answer session as well as today's program. Thank you, ladies and gentlemen, for your participation. You may now disconnect. Good day.