HPK - NASDAQ

Thank you for standing by, and welcome to HighPeak Energy's Second Quarter 2025 Earnings Conference Call. [Operator Instructions] I would now like to hand the call over to Steven Tholen, CFO. Please go ahead.

Good morning, everyone, and welcome to HighPeak Energy's Second Quarter 2025 Earnings Call. Representing HighPeak today are Chairman and CEO, Jack Hightower; President, Michael Hollis; Vice President of Business Development, Ryan Hightower; and I am Steven Tholen, the Chief Financial Officer. During today's call, we may refer to our August investor presentation and our second quarter earnings release, which can be found on HighPeak's website. Today's call participants may make certain forward-looking statements relating to the company's financial condition, results of operations, expectations, plans, goals, assumptions and future performance. 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 in our August investor presentation. I will now turn the call over to our Chairman and CEO, Jack Hightower.

Thank you, Steve. Good morning, ladies and gentlemen, and thank you for joining us today for HighPeak Energy's second quarter conference call. I'd like to thank the entire HighPeak team for all their hard work and continued dedication to the company while I was out during the quarter recovering from my accident. I'm extremely fortunate to report that I'm feeling much better, and I'm now back in the proverbial saddle. Now turning our attention to HighPeak's second quarter results. We achieved another really strong quarter of production, albeit a little slower than first quarter levels, which was expected due to timing of turned-in-lines and with our deliberate reduction in development activity. In the face of lower commodity prices driven by geopolitical issues, the effect of newly instituted tariffs and global macroeconomic uncertainties, our margins remained quite strong at $33.58 per barrel of oil equivalent, allowing us to generate over $155 million of EBITDAX during the quarter. We reduced activity in mid-May as prudent allocators of capital. And in conjunction with that decision, our second quarter CapEx spend was actually 30% lower than our first quarter spend. I'd like to remind everyone that due to the timing of bringing on large multi-well pads and our deliberate reduction of activity dropping down to 1 rig for a specified period of time and modifying our completion schedule with prescribed pauses of frac activity, our overall volumes will fluctuate from quarter to quarter. However, with our current development plan in place, we still feel confident that we'll achieve our '25 production guidance. We're really excited about the recent refinancing of our term loan and super priority RBL and all the associated benefits, and we've added in some additional hedges since the quarter end, which will help us insulate from further potential downside in commodity prices as we move forward. Now I'd like to turn the call over to Ryan Hightower to discuss the details of the term loan. Ryan?

Thanks, Jack, and good morning, everyone. As Jack mentioned, we recently announced the amendment and extension of our current term loan and super priority revolving credit facility, which has solidified HighPeak's credit profile for the next several years. Outside of some associated upfront fees and expenses, it was a net debt-neutral refinancing transaction. Some of the material amendments and associated benefits to these facilities include the extension of all debt maturities by 2 additional years, pushing out expirations to September 2028. The term loan facility was upsized to $1.2 billion, providing the company with essential additional liquidity. And given the current dynamic macro environment, we elected to push out the quarterly amortization payments until September 2026, which provides the company with more flexibility if we find ourselves in a lower-for-longer commodity price environment. I would like to point out that one of HighPeak's top priorities is still to pay down absolute debt utilizing our free cash flow. So even though the amortization payments are on pause, look for the company to continue to pay down debt as we move forward. A few additional key benefits associated with this transaction include the term loan call protection or make-whole provision was not extended and will expire next month, which provides HighPeak with significant flexibility to pay down this loan at par in whole or in part at any time. In comparison to a new high-yield bond with a standard 2- to 3-year no-call provision, this advantage creates substantial potential savings to the company in strategic alternative scenarios or if interest rates drop meaningfully over the next few years, and we want to lock in a lower rate with a high-yield bond at that time. The total upfront costs associated with this extension were significantly less than other potential financing options. And if you agree with consensus estimates, another key advantage is the floating interest rate structure of the term loan, which will allow the company to benefit from projected lower interest rates. We are deeply thankful for the support of our lenders. This amendment and extension positions us to capitalize on future opportunities while maintaining a strong and adaptable financial foundation. I'll now turn the call over to Steven Tholen to provide a brief update on our hedge profile.

Thank you, Ryan. On a high level, HighPeak's hedging philosophy is focused on protecting our cash flows to fund our capital budget and service our debt. Subsequent to quarter end, when oil prices increased, HighPeak entered into additional crude oil derivative contracts covering a significant portion of our forecasted production volumes through March of 2027. The new hedges consist of mostly collars, but also include a few swaps. The collars generally have a floor price of $60 a barrel, providing HighPeak with downside protection should oil prices decline, but also offering exposure to the upside should oil prices increase. Inclusive of our new hedges, we have over 50% of our volumes hedged for the second half of this year with a weighted average floor price of over $62 per barrel. Going forward, we will systematically hedge a minimum of 50% of our projected PDP crude oil production on a quarterly basis. We also have roughly 90% of our second half 2025 gas volumes hedged at a price of $4.43 per MMBtu. As Jack said earlier, these hedges will help insulate HighPeak from further downside risk in near-term commodity prices. I will now turn the call over to our President, Michael Hollis, to provide an operational update.

Thanks, Steve. As we previously guided to the market that our 2025 development program was first half weighted, as shown by our first and second quarter CapEx spend rates, as you can see depicted on Slide 8 of our company presentation. In conjunction with the updated development plan, we laid out our first quarter earnings call, we reduced activity down to 1 rig in mid-May, primarily as a result of the material D&C efficiency gains that we experienced over the last few quarters as well as in reaction to market and commodity price volatility post Liberation Day. HighPeak's second quarter CapEx was 30% lower than the first quarter, which was in line with our internal expectations. Again, on Slide 8, you can see the monthly step down of capital spend, which decreased significantly after we dropped the second rig. June reflects the first full month running a single rig and is representative of what the 1-rig cadence spend rate would be. Looking forward, our plan remains to add the second rig in September. However, we are continuing to monitor commodity prices, the backwardation in the near-term as well as long-term strip, the overall market and our current cost structure, and we will remain flexible to adapt to those variables. Let me stress that we are not contractually obligated on any rig or frac crew. And as I mentioned on last quarter's call, HighPeak has total flexibility from a land and operations perspective to reduce the budget and leave a rig down for longer or make any other appropriate changes to slow our capital spend depending on market conditions. Now to completion efficiencies. We are continuing to see D&C cost coming down. We are currently realizing low-single digit declines from where we were last quarter. I mentioned on last quarter's call, we revised our development schedule was going to afford us the luxury of introducing simul-frac operations on some of our completion jobs. During the second quarter, we completed our first simul-frac job on our Lorin Pad in Borden County. This was a 4-well 15,000-foot lateral pad. And I'm proud to report that this project went smoothly and even came in under our initial cost estimates, inclusive of the estimated simul-frac savings. We deployed 80,000 horsepower, completed roughly 4,500 lateral feet per day and utilized 80% recycled fluids for the stimulation. This was a strong first mark on the board for the completions group. Now internally, we anticipated the savings in the neighborhood of $250,000 to $300,000 per well or roughly $1 million on this job. But after all was said and done, we actually saved closer to $400,000 per well, so about $1.6 million of total savings on this completion. This represents about a 10% savings on our total completion costs. HighPeak expects to utilize simul-frac operations on roughly 1/3 of our remaining completions during the balance of 2025 based on our current development schedule, further enhancing our capital efficiency. Given the tremendous success of our first simul-frac, we will look to insert simul-frac ops anywhere that we can fit it into our completion schedule. And now for a quick update on our Middle Spraberry delineation process. Our first Middle Spraberry test in Flat Top, which was a 10,000-foot lateral has cumed over 170,000 barrels of oil plus associated gas in less than 1 year of being turned online, which has significantly outperformed our initial type curve estimates and is consistent with the results of our bread and butter Wolfcamp A and Lower Spraberry wells. This level of first year well performance, coupled with our current cost structure would equate to single well breakevens in the low- to mid-$40 per barrel of oil range. Our second well, which is a 15,000-foot lateral, is continuing to ramp up and looks very encouraging. It has cumed over 50,000 barrels of oil to date. Offset operators have continued to drill and delineate the Middle Spraberry formation around HighPeak's acreage. These are all constructive steps towards delineating approximately 200 Flat Top Middle Spraberry locations that will eventually move into HighPeak's sub-$50 breakeven inventory. And now turning to Signal Peak. We recently turned in line our easternmost Wolfcamp A and Lower Spraberry wells, which include 1 Wolfcamp A and 2 Lower Spraberries. All 3 wells are currently cleaning up and producing a combined 1,500 barrels of oil per day plus associated gas. It's still early in the flowback process, but we are very encouraged by the early results and the development potential this area may provide. Please note that HighPeak does not carry any inventory in these zones east of where these wells have been drilled, but the early encouraging results may allow us to add incremental inventory further east in our block. Our Flat Top solar farm has now been online for a little over a year, reducing our electrical cost as well as our Scope 2 corporate CO2 emissions. From June through December of last year, we realized power savings of about $810,000 while reducing our CO2 emissions by over 4,600 metric tons. The amount of power generated from the solar farm, while it was online for 7 months in 2024, was the equivalent of the annual energy usage of roughly 1,100 homes. From a social standpoint, we're proud to say that HighPeak is reducing our grid power usage by 10 megawatts during peak summer power demand hours to be utilized by the communities that we operate in. And with my comments now complete, I'll turn the call back to Jack for closing remarks.

Thank you, Mike. In closing, it was a solid quarter for HighPeak. The operations team are doing a stellar job and are laser-focused on optimization and corporate efficiency. The entire organization holds our 4 core pillars paramount. Number one, improving corporate efficiency. The HighPeak machine continues to squeeze out efficiencies throughout the entire development and production process. We're currently realizing low-single digit declines in well costs quarter-over-quarter and the successful use of simul-frac is a true needle mover. And remember, HighPeak expects to simul-frac approximately 1/3 of its completions for the remainder of this year. Number two, maintaining capital discipline. Because of our realized operational efficiency gains in the current state of global economic uncertainty and its impact on oil prices, we had taken the proactive step back in May to modify our drilling cadence by dropping a rig. We're still currently running one drilling rig with the plan to pick up the second sometime next year -- next month, which would allow us to perform all the development work we guided to at the beginning of the year. However, we will continue to monitor market conditions, and we will remain flexible to further adjust our program as those conditions warrant. We have no obligation to add back the rig and may choose to delay its arrival. Number three, optimizing our capital structure. As you may recall, one of the main '25 objectives was to optimize our capital structure. In light of the overall market volatility post Liberation Day, the recent amend and extend of our term loan and revolving credit facility was the best outcome for the company. This action prevented the prior outstanding term loan balance from going current on our balance sheet in September. This refinancing has solidified our credit profile by extending our debt maturities until 2028. It's increased our liquidity, minimized our upfront refinancing costs and provided us with the benefit of realizing potential interest expense savings. If interest rates come down over the next few years as projected by consensus estimates, in addition with the prepayment penalty set to expire next month, we will have the ultimate flexibility of continuing to pay down debt at par as we generate free cash flow moving forward. Four, creating shareholder value. This is the time to stay nimble and prudent, which our high-quality asset base allows us to do. Management continues to be hyper focused on long-term value creation. And it's important to remember that while markets may be temporarily volatile, the fundamental value of our asset base remains strong. We're fortunate to have a long runway of high-value drilling locations at a time when core inventory is becoming increasingly scarce, and we have the ultimate flexibility to develop our inventory when market conditions provide for realizing maximum return. Thank you very much, and now we'll open up the call to questions.

[Operator Instructions] Our first question comes from the line of Jeff Robertson of Water Tower Research.

On the financing side, Steve or Ryan, can you talk a little bit about how much liquidity you want to maintain? And I'm just thinking about it in the context of the ability to pay off principal amounts on the term loan as you look at the rest of 2025. I know the required amortization expires, but you have the flexibility to pay off term loan balance with excess cash flow to the extent you maintain whatever liquidity level you're looking at?

So Jeff, I think we'd like to maintain a fair amount of liquidity. It's going to be based on where oil prices are. We're also where we're able to put in hedges that protect us on the downside if oil prices should turn down. But it be our intent that over the course of time that as we generate free cash flow that we will use that free cash flow to pay down debt. But we have currently over $200 million to over $250 million of liquidity at this point in time. It's a number that we feel pretty comfortable with. And -- but it will be dependent on where oil prices go as we go forward.

Steve, on the cash flow statement, can you talk at all about the swings in the working capital changes that are in the investing cash flows and how that might trend over the rest of 2025 with the capital program you have in place?

Yes. So what you're seeing there is the effect of reducing from 1 -- from 2 rigs down to 1 rig. And as a consequence, there was a large adjustment in the accounts payable and working capital during the second quarter. As we are at 1 rig and we -- through the end of -- or through the majority of the third quarter, we'd expect that number to be relatively static as we go forward as we pick up a second rig in September or later this year, we would expect that number to increase and be a benefit to the cash flow from operations.

And Jeff, also remember that we had some infrastructure projects that kind of ran through the latter half of Q1 and some of the bills flow into Q2. So some of that is part of this net working capital that you saw in Q2 as we dropped activity.

Yes. Yes.

Mike, with respect to operations, you said you're going to -- about 1/3 of the remaining completions will be via simul-frac. Is there a limit on -- or is there -- are there any limiting factors on why you couldn't complete more wells with simul-frac? Or does it just depend on where they're drilled and what pads and how the development cadence works out?

You bet, Jeff. Obviously, when you're playing with kind of the rule of small numbers, which would be 1 to 2 rigs and today, 1, it's a little bit more difficult to drill large kind of 4, 6-well pads. We have some of those that we have to complete in the rest of this year. Now as you -- so again, in simul-fracking, you are fracking 2 wells at one time and usually doing wireline perforation work on the other 2. So ideal is 4 or more wells on a pad to be able to simul-frac effectively and efficiently. However, we are going to start looking at how we could do what we are kind of coining hybrid simul-fracs on wells or pads that may only have 3 pad or 3 wells on a pad. It won't be the same kind of $250,000 to $400,000 of savings. It might be more like $50,000 to $100,000. But we are looking at that to see how we can utilize this more effectively on a higher percentage of our completions, both this year as well as going into the future. Obviously, with a higher number of wells that you drill or number of rig count, it's much easier to have at least 4 or more wells on a pad. So hopefully, that kind of gives you a little color.

And then in the deck, you say it shows that you have 20 wells in progress at the end of the second quarter. How does the inventory of wells in progress and looking out into 2026 affect your decision-making as to whether or not to add a second rig this fall?

So the 20 DUCs that we came into the quarter with kind of an average rule of thumb per operating rig would be roughly 10 per operating rig behind it because you're always either drilling on a pad with some wells that have DUCs or you're completing, drilling out, putting equipment in. So coming into second quarter and having 20 makes perfect sense. Now the longer that we run just 1 rig and complete at our normal cadence, you'll start to see the DUC count behind us start to come down and approach that 10 wells if we were to do it per rig if you're only running 1 rig, and you did that for an extended period of time. So do I think it's going to come down to 18, 17 by the end of the year, that's probably a pretty good number. Now to that point, whether or not we were to pick a rig up or not this year, we have almost every well drilled currently that will be completed this year.

On the operational highlights, you talked about the Middle Spraberry, Mike. Will you see -- do you anticipate that you will see much of an impact from that inventory on your year-end 2025 reserve numbers?

So the answer will be obviously a lot more impact than we had in 2024, right, because we had just drilled 1 well and so really very few to no PUDs associated with it. I think it would be reasonable to expect that we would probably drill 1 to 2 more Middle Spraberries this year, plus the additional drilling that's been done off to our flanks by our offset operators could add some additional PUDs associated with those. So yes, the total number of PUDs associated with Middle Spraberry wells at the end of 2025 will be significantly higher than it was in '24.

And lastly, if I can, can you talk based on the completion schedule that you look at, can you talk a little bit about where you think production might go over the next couple of quarters?

You bet. No. And obviously, Jack kind of mentioned it, when you're doing these pads, you do get a little bit of lumpiness. I think when you look at our yearly production guide and the fact that Q1, we had a pretty good month where everything kind of timing-wise ebb and flowed in our direction. And then you look at second quarter, it's just a matter of timing of when we brought these wells on. And obviously, when you frac wells, you water pads out on either side. So you'll see some fluctuations quarter-to-quarter. In Q1, obviously, we model out all of these things. So you saw a very modest change in our midpoint of our guide for our production. And I think looking forward, that will be a pretty good guide for everyone from where we are to the endpoint. Again, we don't give quarterly guidance for that reason, but I think our yearly guidance is still solid, yes.