HighPeak Energy, Inc. Q1 FY2026 earnings call

First quarter results - Production: Strong start, production averaged ~46,000 BOEs per day, 7.5% above guidance midpoint; oil production up 10% q/q. - Cost: Lease operating expense per BOE more than 17% below guided range, ~22% below fourth quarter level; absolute operating costs declined ~$7.4 million q/q. - Drivers of cost improvement: Optimization of chemical program, more efficient use of field gas, continued electrification. - Development program: First quarter drilling and turn in line activity ~one third of planned 2026 program; capital spending ~29% of full year budget; exited quarter with 18 wells in progress. - Capital discipline and efficiency: Reduced capital program by ~50% vs last year, moved to maintenance mode development strategy to hold production flat while maximizing free cash flow; net oil produced per dollar of capital invested improved over 60% q/q. - Base optimization: Executed 16 targeted workover projects, increased oil production, leveraged existing infrastructure, generated high margin barrels. - Broader environment: Focus on back end of commodity curve; ~40% average exposure to spot oil prices with hedge floor in mid $60 per barrel range; generated over $21 million of free cash flow excluding changes in working capital in first quarter. - Balance sheet: Put on at - the - market or ATM program to issue up to $150 million of common stock for flexibility, use of proceeds for reducing debt, increasing liquidity, strengthening balance sheet. - Year focus: Strengthen balance sheet through free cash flow generation, debt reduction, etc.; preserve high quality inventory by developing at disciplined pace and optimizing wells; improve corporate efficiency focusing on returns, create long - term equity value.

Production averaged approximately 46,000 BOEs per day, which was about 7.5% above the midpoint of guidance range. Oil production was 10% quarter over quarter. Lease operating expense per BOE was more than 17% below guided range, roughly 22% below fourth quarter level. Capital spending came in right in line with expectations at about 29% of full year budget. Net oil produced per dollar of capital invested improved by more than 60% quarter over quarter. Executed 16 targeted workover projects which increased production from roughly 1,600 barrels of oil per day to about 2,600 barrels of oil per day, an average increase of 63% per well for those 16 wells.

Production - Production profile in 2026 expected to be flat, similar to current pace with potential to be in upper portion of guided range. - 2027 activity expected to be very similar to 2026 program, with capex spend at midpoint of about $270 million. - Free cash flow: If prices remain higher for longer, free cash flow number moves up materially, accelerating balance sheet strengthening.

Q: Given where you are with production and 60% of estimated 26 capital going or being spent in the first half of the year, can you share some color on production levels progression in the back half of the year and with the inventory of ducts that you might exit 26 Any early color or preliminary color on 2027?

A: As laid out in guidance last quarter, planning to spend roughly 60% of budget in first half of year, right along that in Q1. Activity in Q2 will be very similar to Q1. From production standpoint, running hot to guide today and up through quarter to date. Latter half of 2026, additional work in first half will be wells producing in second half. 2027 activity expected to be very similar to 2026 program, will exit with roughly 9 to 10 ducks in 2026 going into 2027.

Q: If you're looking at kind of a capex spend in 27, I think what we have this year at the midpoint of about $270 million is where you need to be, you know, kind of coalescing for modeling purposes.

A: Assumes very similar program to 2026.

Q: On your work over efforts, are you doing anything differently to try to identify wells that need some attention and therefore justify the expense of going in and spending capital that turns into LOE expense results in the increased production that you highlighted on slide seven?

A: Have upwards to close to 400 horizontal wells producing. Have list of wells that would benefit from intervention. Typically looking for wells that were going to be touched anyway and met requirements. Well interventions are mini - stimulations, seeing good results, and this will increase total recovery of the area.

Q: Ryan or Mike, you had big working capital swings in the first quarter which impacted pre - cash flow as you noted in your remarks. Can you talk about how much of that activity was isolated to one quarter events and how we should think about that as you move forward through 2026?

A: For bulk of fourth quarter, ran two rigs and had couple of large simulfrac jobs, resulting in negative working capital swing of about $35 million in Q1. All that's behind us now, on go forward basis more steady state.

Q: High Peak had a big unrealized mark - to - market hedge gain in the first quarter, which obviously impacted reported earnings. Can you talk about how that gain would be treated as you move forward in 2026 in a potentially lower oil price environment than what ended the first quarter?

A: Total derivatives loss in first quarter on paper was about $55 million, only 17.4 of that was actual cash loss, rest was marked market loss as of March 31. If prices pull back to lower levels throughout rest of year, market loss and potential cash hedge loss would shrink as year progresses.

Q: I'm curious to dig in a little bit more on the workovers. I know you have this slide kind of talking about the benefits of that. It looks like the workover expense for the quarter was actually pretty low relative to kind of what the run rate was in 2025. And so just trying to understand, I guess, what the activity expectation is going forward.

A: LOE is two buckets: chemical and day - to - day LOE, and work over expense. Work over expense started marching up in latter half to three quarters of 2025. Reasonable run rate for work over expense is probably somewhere in 75 cents to a dollar range. Some workovers are expense work (getting well back to original state) and some are capital workovers (adding reserves). Overall total cost is coming down.

Q: One other piece of this, and I don't know if it's connected or not. I mean, it sounds like it might have been. I guess second half of last year, as you stepped out into, I think it was further to the east, you had some of the issues with kind of finding the, I guess, where you had water encroachment and in some of the newer extensional wells. i guess where does that stand are those wells i mean we just has that area just been kind of written off at this point and are those wells just not really part of the existing production or any plan going forward?

A: Encountered extraneous water production in that area, only zone with inventory was Wolf Camp A. Not going to drill another well in that area, equated to about 18 wells coming out of inventory. Existing wells there are producing, have done interventions to reduce water coming in, they are economic but lower production.

Q: Yeah, no, great question. And again, we constantly highlight the infrastructure that High Peak has put in place over the last five plus years. And to your question there on the water system, if you look back a couple of years, we were running six rigs. three frack crews, and looking to build to 75 to 100,000 barrels of oil a day. Now, with that, you need to be able to handle 400,000 barrels of water per day. So we put in very large pipes, very large pumps, several SWDs, so our SWD capacity is a little over 400,000 barrels of capacity today. Think pipelines that are 24 inches in diameter, we can move around 400,000 barrels a day. And of course, we recycle almost 95% of what we use on the stimulation side. But to give you an idea of where we sit today, where we're producing roughly, you know, on the gross spaces of oil that we produce, it's pretty close to 45,000 to 47,000 barrel gross of oil. So with that kind of four to one, we're a little over 200, call it 210, 220,000 barrels of water a day being produced across High Peak. Some of that, a little bit more than four times is because you have some flow back from your new fracked wells. But we're about 45 to 50% utilized of capacity that High Peak has. We take very little third party water into our system. It's available. So for folks near and around us, we do have plenty of capacity for disposal. But the infrastructure was built for life of field, and that stretches across our oil, gas, electrical, recycle capability. All of that's built in place. And I think you're seeing that on our LOE cost numbers. And then same thing on our CapEx numbers. As we have built all of our large central tank batteries, you're starting to see the cost per well go way down. Because today when we drill a new well, all we have to do is add some metering equipment to tie it into an existing battery that's already there.