HPK - NASDAQ

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. [Operator Instructions] 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. But everything that we're doing, relative to our plan going forward this year and next year can be synopsized on this slide. And I know that the market hadn't liked our stock today and our press release, but I think 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 as low as it is because we're more excited about the company right now than we ever have been and 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 present stock price. Looking at this and 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 minimum effect on our growth trajectory. We plan to accomplish this through 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 relatively 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. And relative to financial discipline, doing this allows us to stay way below one time maximum leverage range, which has always been our philosophy. For 53 years, we never want to get out over our skis, it's why we've never had any losses on any transaction in 53 years. 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. In addition, 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%. So, almost 50% this year and a 30% increase next year, generating material free cash flow. 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, 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 flattish 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 at 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, it actually gives you on '23, high 50,000 barrels of oil a day range and in '24, an exit of over 70,000 barrels a day. On any kind of reasonable metrics that you're looking at as a multiple of cash flow, considering the number of locations that we have, and it shows over 2,500 on this slide, and that's a conservative estimate on the number of locations that are commercial for this company. That's still great growth and great exit -- potential exit strategy 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 and a flat $80 price deck. And you can see how that goes up with higher prices. In addition, we will be positioned to continue increasing our production next year at a four rig, funded 100% from cash flow from operations, and that's -- not very many companies that are in growth mode can do that. Now turning to Slide 7. This is perhaps one of the most important slides. We've talked about our operating margins, but we continue both historically and this year and into the future, to have the highest margins of our Permian peer. 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 on our peers. That's important relative to our price, important relative to strategic alternatives that we literally at year-end will have almost 90,000 barrels compared to 60,000 barrels that we're producing is equal to 90,000 barrels that other people are producing to get that same cash flow and value. So, our high oil cut our low production operations, low cost operations, increasing production will continue to differentiate our barrel of oil equivalents relative to our peers. Mike, I'm going to now turn the call over to you for 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 across both blocks and stratigraphically in 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. And 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. 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. And HighPeak has been very active in and amongst our producing areas. Also, 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 obviously 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, HighPeak's capital cost to drill and complete fleet 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 for 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. So as you can imagine, 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 similar 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 give line of sight to 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 pink sticks blanketing the acreage, these are all 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 higher production, equating to much higher returns. We have continued to delineate these zones as shown by bullets one and two. And 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, that we refer to the three -- or we refer 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 feel for 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 down costs. 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'd 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 make for 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 looks at 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. And 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 have 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 is representative of our central tank batteries that are scalable, efficient and environmentally friendly. And 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, better economics. As you go to the east though, we're finding out on a comparative analysis compared with the western half that in this area, margins are differentiated from other areas of the basin and our 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. Further, HighPeak is outperforming its peers in the eastern part of the county. All of these things confirm that Howard County, as we mentioned earlier, is an area in the Midland Basin that will continue to provide strong shareholder returns. The other thing I would point out 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 what we have. We have multiple zones that are going to be commercial in that area and we're extremely excited about it. We know now down south at Signal Peak, the economic returns in the Wolf D are not quite as high, but they're still very commercial, very good. We have wells north and west and east and south, full delineation of the Wolfcamp D and we know that the 3-Fingers looks to be a little bit better than the basic Wolfcamp D. The other thing is, half our acreage position to the South looks to be good in the Wolf A and the Lower Sprayberry as Mike mentioned. So 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. The other thing that's important is this 2,500 gross locations is not speculation. Pulling back on our drilling program wasn't done because we don't have confidence in our inventory, we had better confidence and our wells are actually 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 get to a high production basis and stay there, and stay there within positive cash flow. We still continue maintaining peer-leading margins and a cost structure among public companies that's better. We're highly oil-weighted inventory with 85% of production being oil and 94% liquids. This is going to continue forward because of our area and the oil cut that we have in that area. And importantly, we are entering an era of free cash flow within the second half of this year, and that will allow us to stay at about 0.5 turn debt-to-equity -- or debt-to-EBITDA as we go forward. So, we're doing everything within the framework of cash flow and we still continue growing the company. There just aren't many companies out there that are fairly young like we are that have the opportunity to do that. So, other than that there's not really anything left to say. I'll just end my comments now and would like to open up the call for questions.

Thank you. At this time, we will conduct a Q&A session. [Operator Instructions] 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 what -- how you're thinking about those notes?

Yeah, Jeff. I know everybody is worried about that because basically relative to current ratio, those first notes are due and -- but yet, 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. The other thing relative to the notes, we could extend those notes or we can do other things to make sure that we're taking care of that situation by converting to longer-term debt. And as I mentioned, we have a plan in place and we'll be announcing something very shortly that takes care of any perceived liquidity issue that any shareholder might have. That's going to be taken care of. We had the plan in place for quite some time, and we'll be exercising 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.

Was that -- 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 very long. We frac them. Then we put ESPs in the ground. So they're all going to look fairly similar the first few months of our production. Again, because you're limited on pump capacity and how hard we want to pull the well for those first few months. So that's part of the reason why they all are kind of line-up since the performance is pretty similar. And then later on when you start seeing a little bit 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 here is that we're getting more effective drainage and you're starting to see that. Obviously early time, it's hard to see because you're pump limited.

Okay. Lastly, Mike, I believe the LOE and your -- you included about $1.25 per BOE of LOE expense in Q1 '23. Can you talk about the main components of that? And how do you see LOEs trending over the rest of this year?

You bet, Jeff. So, the $1.26 or so that you're referring to on the workover expense, so we were fracking with three frac crews up in Flat Top. So, we were utilizing a large amount of our produced fluid, which allowed us to go in and do some repairs to a couple of our SWDs up in Flat Top that we've been waiting for the right time to do. So, this was a great time to do it. So, about three quarters of that $1.26 was just those SWD repairs. Now that they're done and we're reducing activity, those SWDs are there for us to use and keep our cost and OpEx low. As we go forward, beginning with the first quarter, we brought on a bunch of new wells. Production, as I mentioned earlier, typically takes a month and a half to two months to hit peak oil. So when you turn on a larger number of these wells, you have the cost associated with lifting that fluid and very little BOEs at that time to divide by. So, when you look at our trends throughout the rest of this year, it's definitely going to be down into the right. Again, we've removed a lot of generators with our overhead electric that we built out. Now, as we picked up new acreage and stepped out and we've done some of this delineation testing, we've had to use a fair number of generators in the first quarter until we got that overhead power built out to those new tank batteries and facilities. So, again, as we go forward, you'll see LOE trend down and we've guided as such, and I think that's going to be very achievable and representative of what we'll be able to do this year.

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 kind of a higher level field level production. As you kind of look at the first quarter, I was curious if you have a sense or maybe an estimate on -- with the 32 wells that are brought online, how much did that impact kind of the base of production in the first quarter relative to what you saw in the fourth quarter? And as you kind of see a little bit of pullback in activity for the remainder of the year, how do you think about what the impact of kind of shut-in production offsetting completions everything? How do you think about that impact, as you kind of slow things down a little bit for the remainder of the year?

You bet, Nick. That's a couple of questions embedded there. I'll kind of try to hit each one of them. If I miss one, jump back in on me. Kind of first quarter, you nailed it, roughly 20 producing wells were taken offline for us to be able to frac the activity that we kind of showed on that slide for Flat Top in those red dash or dotted boxes. So that amount of production was offline. And then of course, we fracked all of our wells. We now have brought on the 20 or so wells that were turned off and are bringing on all of those wells that we completed throughout the first quarter. So, throughout Q2 and Q3, you're going to see significant growth from all of that activity that we did in the first quarter. Remember, we were running six rigs and we had four frac crews. Now, to your other question. So again, there is a high level of activity in water out effect associated with that much fracking. Now as we go forward, we're level loaded with two frac crews throughout this year and into 2024, which is about a four rig cadence. Now, since we had drilled with six rigs for a period of time, we will be able to level load those two frac crews throughout the year just by drilling with two rigs through the remainder of this year. Into '24, we'll have to step back up to the four drilling rigs to continue to feed the two frac crews running. So to your point about what will water out effect look like going for the rest of this year and into next year, it will obviously be less water out because you have less activity, but also would be noticed with the way we've got kind of Flat Top laid out as well as Signal Peak, the activity will no longer be kind of a book ended by production on both sides. The vast majority of it will just have production on one side, so again, reducing the amount of water out. So, I think what you'll see throughout the rest of this year and '24 is a smaller percentage -- a smaller total amount of oil being taken offline as we're completing these wells, but a much lower percentage because our base production is going to grow significantly.

Thanks, Mike. That's really helpful. Do you -- how do you quantify that internally? As you think about quarter-to-quarter and that as you have grown as a company, seen this production base gets bigger, how do you think about, I guess, quantifying what you expect to be shut-in on a volume basis kind of over the past few quarters? Or is that not how you think about it?

Well, we did -- Nick, this is Jack. We do think about it, and of course since I'm responsible for allocating capital, undoubtedly, and I'm also responsible for trying to hit our numbers. But when you're growing like we are and if you have any problem at all on a multi-well pad, you're in a situation where you know you're having to take wells offline, you just don't know how long it's going to take you to get those wells back online. So there's not anything relative to the geological or the formation or the performance, it's simply timing. Timing is the only issue. And you've got supply chain issues, you've got all kinds of issues, but at the end of the day, it's moving quickly into an infrastructure, and with this kind of growth, sometimes your timing is faster than you anticipate, sometimes it's a little bit longer, hence the reason why we have, what I call, plateau or platform development where you have some interference with lumpy production, your production for two quarters kind of stays the same, and then all of a sudden you have a big jump in production. And as Mike said, with all the 20 wells that were offline, 20 more wells being completed and those wells coming online in 45 to 60 days, we expect our production -- in fact, our production is already above where we were at the exit of the first quarter and it'll be continuing going up into this quarter, very similar to our increases in the past.

Hey Nick, just to kind of expand on that a little bit. So, we surgically go into the model, and when we are completing a pad and we surgically turn off the offset wells that we turn off and then we even go outside of that kind of a halo to reduce production from the offset wells to account for any water impact that we may see. And to Jack's point, there's timing associated with all of that. So, we try to be very conservative with the timing of when we would bring those wells back on and when they get back to their type-curve. So, all of that is represented and taken in account in the model and what we project throughout the year for our production.

Got it. That's very helpful. And just, on a modeling kind of standpoint, as you look at kind of the remaining -- the remainder of the year in terms of the kind of expected wells to be brought online, is that fairly steady state across each quarter? Like, how should I think about the shape of like what you all are planning on bringing online for the rest of the year at the kind of [newer] (ph) wells?

Nick, you're pretty well spot on. Obviously, it's a little higher in Q1, but when you're looking at turning on 110 wells for this year and we brought online about 25 in the first quarter, you can imagine with all the activity in Q1, turning lines might be a little higher in Q2, but change ratably throughout the rest of the year to get to that kind of 110 number. And since we're keeping two frac crews running, 2024 looks very similar to 2023 in total number of deals that we'll have next year as well.

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

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

I appreciate that. Thank you.

Thank you, Nick.

Thank you, Nick. I am showing no further questions. So, I will now pass it over to Jack Hightower for final remarks.

I just want to thank everybody for being here for the conference call. It's a great time to buy HighPeak stock. It checks all the boxes. And considering all the important points, it's why I'm extremely confident in our ability to optimize the value for our shareholders either through continued exploitation or through strategic alternatives. I wish I could speak more about that, but everything is on pace and we're very excited about the opportunity for the stock in the future. Other than that, thank you for attending.