Q2 2025 HighPeak Energy Inc Earnings Call

Speaker 2: Thank you for standing by and welcome to HighPeak Energy's second quarter 2025 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 11 on your telephone. To remove yourself from the queue, you may press star 11 again. I would now like to hand the call over to Steven Tholen, Chief Financial Officer. Please go ahead.

Speaker #2: Thank you for standing by, and welcome to HighPeak Energy's second quarter 2025 earnings conference call. At this time, all participants are in listen-only mode.

Speaker #2: After the speaker presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press *11 on your telephone.

Speaker #2: To remove yourself from the queue, you may press *11 again. I would now like to hand the call over to Steven Tholen, CFO. Please go ahead.

Steven Tholen: 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'm 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 operation, expectations, plans, goals, assumptions, and future performance. 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.

Speaker #3: 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.

Speaker #3: 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.

Speaker #3: 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.

Speaker #3: 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.

Steven Tholen: 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.

Speaker #3: I will now turn the call over to our Chairman and CEO, Jack Hightower.

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 would 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 am extremely fortunate to report that I am feeling much better and am now back in the proverbial saddle. 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.

Speaker #4: 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.

Speaker #4: I'm extremely fortunate to report that I'm feeling much better and am now back in the provoked real 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 turning lines and with our deliberate reduction in development activity.

Jack Hightower: 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 EBITDA 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 would 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 one 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.

Speaker #4: In the face of lower commodity prices driven by geopolitical issues, the effect of newly instituted tariffs, and global macroeconomic uncertainties, our margins remain quite strong at $33.58 per barrel of oil equivalent.

Speaker #4: 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 spent.

Speaker #4: I'd like to remind everyone that, due to the timing of bringing on large multi-well pads, our deliberate reduction of activity down to one rig for a specified period of time, and the modification of our completion schedule with prescribed pauses in frac activity, our overall volumes will fluctuate from quarter to quarter.

Jack Hightower: However, with our current development plan in place, we still feel confident that we will achieve our 2025 production guidance. We are really excited about the recent refinancing of our term loan and super priority RBL and all the associated benefits. We have 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. I would like to turn the call over to Ryan Hightower to discuss the details of the term loan.

Speaker #4: 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.

Speaker #4: 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.

Speaker #4: And now I’d like to turn the call over to Ryan Hightower to discuss the details of the term loan. Ryan?

Michael Hollis: 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 two 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. 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.

Speaker #5: 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.

Speaker #5: 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.

Speaker #5: Some of the material amendments and associated benefits to these facilities include the extension of all debt maturities by two additional years, pushing out expirations to September 2028.

Speaker #5: 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.

Michael Hollis: 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, where make-hold 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 two to three-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.

Speaker #5: 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.

Speaker #5: A few additional key benefits associated with this transaction include the term loan call protection, or make-hold provision, was not extended. And we'll expire next month, which provides HighPeak with significant flexibility to pay down this loan at par and hold or in part at any time.

Speaker #5: In comparison to a new high-yield bond with a standard two to three-year no-call provision, this advantage creates substantial potential savings to the company and 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.

Michael Hollis: The total upfront costs associated with this extension were significantly less than other potential financing options. 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.

Speaker #5: The total upfront costs associated with this extension were significantly less than other potential financing options. 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.

Speaker #5: 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.

Speaker #5: I'll now turn the call over to Steven Tholen to provide a brief update on our hedge profile.

Steven Tholen: 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 callers, but also include a few swaps. The callers 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.

Speaker #6: 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.

Speaker #6: 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.

Speaker #6: 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.

Speaker #6: 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.

Speaker #6: 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.

Steven Tholen: 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.

Speaker #6: 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.

Michael Hollis: Thanks, Steve. As we previously guided to the market, 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 eight of our company presentation. In conjunction with the updated development plan, we laid out our first quarter earnings call. We reduced activity down to one rig in mid-May, primarily as a result of the material DNC 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 eight, you can see the monthly step-down of capital spend, which decreased significantly after we dropped the second rig.

Speaker #7: Thanks, Steve. As we previously guided to the market, 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 eight of our company presentation.

Speaker #7: In conjunction with the updated development plan, we laid out our first quarter earnings call, we reduced activity down to one rig in mid-May, primarily as a result of the material D&C efficiency gains that we experienced over the last few quarters.

Speaker #7: 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.

Speaker #7: Again, on slide eight, 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 one rig cadence spend rate would be.

Michael Hollis: June reflects the first full month running a single rig and is representative of what the one-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 call 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. 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 DNC costs coming down.

Speaker #7: 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 in our current cost structure, and we will remain flexible to adapt to those variables.

Speaker #7: Let me stress that we are not contractually obligated on any rig or frac route. As I mentioned on last quarter's call, HighPeak has total flexibility from a land and operations perspective to reduce the budget, leave a rig down for longer, or make any other appropriate changes to slow our capital spend depending on market conditions.

Speaker #7: Now to completion efficiencies. We are continuing to see D&C costs coming down. We are currently realizing low single-digit declines from where we were last quarter.

Michael Hollis: 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 Warren pad in Borden County. This was a four-well, 15,000-foot lateral pad. I am 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. Internally, we anticipated the savings in the neighborhood of $250,000 to $300,000 per well, or roughly $1 million on this job.

Speaker #7: I mentioned on last quarter's call we revised our development schedule, which was going to afford us the luxury of introducing simul frac operations on some of our completion jobs.

Speaker #7: During the second quarter, we completed our first simul frac job on our lower-end end pad in Borden County. This was a four-well, 15,000-foot lateral pad.

Speaker #7: 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.

Speaker #7: We deployed 80,000 horsepower, completed roughly 4,500 lateral feet per day, and utilized 80% recycled fluids for the simulation. This was a strong first mark on the board for the completion screw.

Speaker #7: 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.

Michael Hollis: 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 a third 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. Now for a quick update on our Middle Sprayberry delineation process.

Speaker #7: This represents about a 10% savings on our total completion costs. HighPeak expects to utilize simul frac operations on roughly a third of our remaining completions during the balance of 2025, based on our current development schedule further enhancing our capital efficiency.

Speaker #7: Given the tremendous success of our first simul frac, we will look to insert simul frac operations anywhere that we can fit it into our completion schedule.

Speaker #7: And now for a quick update on our middle sprayberry delineation process. Our first middle sprayberry test in Flat Top, which was a 10,000-foot lateral, has teamed over 170,000 barrels of oil, plus associated gas, in less than one year of being turned online which has significantly outperformed our initial tight curve estimates and is consistent with the results of our bread-and-butter wolf campaign in lower sprayberry wells.

Michael Hollis: Our first Middle Sprayberry 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 one 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 Sprayberry 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. All set operators have continued to drill and delineate the Middle Sprayberry formation around HighPeak's acreage.

Speaker #7: This level of first-year well performance, coupled with our current cost structure, would equate to single well break-evens in the low to mid $40 per barrel of oil range.

Speaker #7: Our second well, which is a 15,000-foot lateral, is continuing to ramp up and looks very encouraging. It has cumulatively produced over 50,000 barrels of oil to date.

Speaker #7: All set operators have continued to drill and delineate the Middle Sprayberry formation around HighPeak's acreage. These are all constructive steps toward delineating approximately 200 Flat Top Middle Sprayberry locations that will eventually move into HighPeak's sub-$50 break-even inventory.

Michael Hollis: These are all constructive steps towards delineating approximately 200 flat top Middle Sprayberry locations that will eventually move into HighPeak's sub $50 breakeven inventory. Now turning to Signal Peak, we recently turned in line our easternmost Wolfcamp A and Lower Sprayberry wells, which include one Wolfcamp A and two Lower Sprayberries. All three wells are currently cleaning up and producing a combined 1,500 barrels of oil per day plus associated gas. It is 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.

Speaker #7: And now, turning to Signal Peak. We recently turned in line our easternmost Wolf campaign in Lower Sprayberry wells, which include one Wolf campaign and two Lower Sprayberries.

Speaker #7: All three wells are currently cleaning up and producing a combined 1,500 barrels of cool per day plus associated gas. It's still early in the flowback process, but we are very encouraged by the early results.

Speaker #7: And the development potential of 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.

Michael Hollis: 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 seven months in 2024 was the equivalent of the annual energy usage of roughly 1,100 homes. From a social standpoint, we are 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. With my comments now complete, I will turn the call back to Jack for closing remarks.

Speaker #7: Our Flat Top solar farm has now been online for a little over a year, reducing our electrical costs as well as our Scope 2 corporate CO2 emissions.

Speaker #7: From June through December of last year, we realized power savings of about 810,000 dollars while reducing our CO2 emissions by over 4,600 metric tons.

Speaker #7: The amount of power generated from the solar farm while it was online for seven months in 2024 was the equivalent of the annual energy usage of roughly 1,100 homes.

Speaker #7: 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.

Speaker #7: And with my comments now complete, I'll turn the call back to Jack for closing remarks.

Jack Hightower: 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 four core pillars paramount. Number one, improving corporate efficiency. The HighPeak machine continues to squeeze out efficiencies throughout the entire development and production process. We are currently realizing low single-digit declines in well cost quarter over quarter, and the successful use of simul frac is a true needle mover. Remember, HighPeak expects to simul frac approximately one-third of its completions for the remainder of this year. Number two, maintaining capital discipline.

Speaker #4: Thank you, Mike. In closing, it was a solid quarter for HighPeak. The operations team is doing a stellar job, and our laser focus on optimization and corporate efficiency.

Speaker #4: The entire organization holds our four core pillars paramount. Number one, improving corporate efficiency. The HighPeak machine continues to squeeze out efficiencies throughout the entire development and production process.

Speaker #4: 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 one-third of its completions for the remainder of this year.

Speaker #4: Number two, maintaining capital discipline. Because of our realized operational efficiency gains and 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.

Jack Hightower: 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 are still currently running one drilling rig with the plan to pick up the second sometime 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.

Speaker #4: We're still currently running one drilling rig with the plan to pick up the second sometime next month, which would allow us to perform all the development work we guided to at the beginning of the year.

Speaker #4: 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.

Speaker #4: 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.

Jack Hightower: 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 has 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.

Speaker #4: 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.

Speaker #4: 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 to 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.

Speaker #4: 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.

Jack Hightower: 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 is important to remember that while markets may be temporarily volatile, the fundamental value of our asset base remains strong. We are 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 will open up the call to questions.

Speaker #4: We're fortunate to have a long runway of high-value drilling locations at a time when core inventories becoming increasingly scarce. And we have the ultimate flexibility to develop our inventory when market conditions provide for realizing maximum return.

Speaker #4: Thank you very much, and now we'll open up the call to questions.

Speaker 2: Thank you. As a reminder, to ask a question, you will need to press star 11 on your telephone. Again, that is star 11 to ask a question. To remove yourself from the queue, you may press star 11 again. Please stand by while we compile the Q&A roster. Once again, that is star 11 to ask a question. Our first question comes from the line of Jeff Robertson of Water Tower Research. Please go ahead, Jeff.

Speaker #2: Thank you. As a reminder, to ask a question, you will need to press *11 on your telephone. Again, that's *11 to ask a question.

Speaker #2: To remove yourself from the queue, you may press *11 again. Please stand by while we compile the Q&A roster. And once again, that's *11 to ask a question.

Speaker #2: Our first question, comes from the line of Jeff Robertson of Water Tower Research. Please go ahead, Jeff.

Jeff Robertson: Thank you. Good morning. On the financing side, Steven Tholen or Ryan Hightower, can you talk a little bit about how much liquidity you want to maintain? I am just thinking about it in the context of the ability to pay off principal amounts on the term loan as you look at either 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 are looking at.

Speaker #8: Thank you. Good morning. On the financing side, Steve or Ryan, can you talk a little bit about how much liquidity you want to maintain and, 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 either the rest of 2025.

Speaker #8: I know the amortization, 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.

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

Speaker #3: So Jeff, you know, I think we'd like to maintain a fair amount of liquidity. It's going to be based on where oil prices are and where we're also where we're able to put in hedges that protect us and the downside if oil prices should turn down.

Speaker #3: But, you know, it'd be our intent that over the course of time, as we generate free cash flow, we will use that free cash flow to pay down debt.

Speaker #3: 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.

Speaker #3: And, you know, but it'll be dependent on where oil prices go as we go forward.

Jeff Robertson: 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?

Speaker #2: Steve, on the cash flow statement, can you talk at all about the swings and the working capital changes that are in the investing cash flows?

Speaker #2: And how that might trend over the rest of 2025 with the capital program you have in place?

Steven Tholen: Yeah. What you are seeing there is the effect of reducing from one or from two rigs down to one rig. As a consequence, there was a large adjustment in the accounts payable and working capital during the second quarter. As we are at one rig and through the end of or through the majority of the third quarter, we would 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.

Speaker #6: Yeah. And so, what you're seeing there is the effect of reducing from from one or from two rigs down to one rig. And as a consequence, there was a large adjustment in the accounts payable and working capital during the second quarter.

Speaker #6: Now, as we are at one rig and we through the end of or through the majority of the third quarter, we would expect that number to be relatively static as we go forward.

Speaker #6: 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.

Michael Hollis: 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. Some of that is part of this working capital that you saw in Q2 as we dropped activity.

Speaker #5: And Jeff, also remember that we had some infrastructure projects that kind of ran through the latter half of Q1, and you know, some of the bills flow into Q2.

Speaker #5: So some of that is part of this, that working capital that you saw in Q2 as we dropped activity.

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

Speaker #3: Yes. Yes.

Speaker #2: Mike, with respect to operations, you said you're going to about one third 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 is it just depend on where they're drilled and what pads and how the development cadence works out?

Michael Hollis: You bet, Jeff. You know, obviously, when you are playing with kind of the rule of small numbers, which would be one to two rigs, and today one, it is a little bit more difficult to drill large, you know, kind of four, six-well pads. We have some of those that we have to complete in the rest of this year. As you so again, in simul fracking, you are fracking two wells at one time and usually doing wireline perforation work on the other two. So ideal is four 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 that are pads that may only have three pads or three wells on a pad.

Speaker #7: You You bet, Jeff. You know, obviously when you're playing with kind of the rule of small numbers, which would be one to two rigs in today one, you know, it's a little bit more difficult to drill large kind of four, six well pads we have some of those that we have to complete and the rest of this year.

Speaker #7: Now, as you so again, in Simul Frac, you are fracking two wells at one time and usually doing wireline perforation work on the other two.

Speaker #7: So ideal is four 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 that are pads that may only have three pads or three wells on a pad.

Michael Hollis: It will not 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 is much easier to have, you know, at least four or more wells on a pad. So, hopefully, that kind of gives you a little color.

Speaker #7: It won't be the same kind of, you know, $250,000 to $400,000 of savings. It might be more like $50,000 to $100,000.

Speaker #7: 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.

Speaker #7: Obviously, with a higher number of wells that you drill or number of rig count, it's much easier to have at least four or more wells on a pad.

Speaker #7: So, you know, hopefully that kind of gives you a little color.

Jeff Robertson: 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?

Speaker #2: 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?

Michael Hollis: 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 are always either drilling on a pad with some wells that have DUCs or you are completing drilling out, putting equipment in. So coming into Q2 and having 20 makes perfect sense. Now, the longer that we run just one rig and complete at our normal cadence, you will start to see that the DUC count behind us start to come down and approach that 10 wells if we were to do it per rig if you are only running one rig. You did that for an extended period of time. Do I think it is going to come down to 18, 17 by the end of the year? That is probably a pretty good number.

Speaker #7: So, you know, the 20 ducks 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 ducks, or you're completing, drilling out, or putting equipment in.

Speaker #7: So, coming into the second quarter and having 20 makes perfect sense. Now, the longer that we run just one rig and complete at our normal cadence, you'll start to see the duck count behind us start to come down.

Speaker #7: And approach that 10 wells if we were to do it, you know, per rig, if you're only running one rig. And you did that for an extended period of time.

Speaker #7: 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.

Michael Hollis: 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.

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

Speaker #2: On the operational highlights, you talked about the Middle Sprayberry, Mike. Will you see, Mike, do you anticipate that you will see much of an impact from that inventory on your year-end 2025 reserve numbers?

Michael Hollis: The answer will be obviously a lot more impact than we had in 2024, right? Because we had just drilled one well and some very few to note puds associated with it. I think it would be reasonable to expect that we would probably drill one to two more Middle Sprayberrys this year, plus the additional drilling that has been done off to our flanks by our offset operators, could add some additional puds associated with those. Yes, the total number of puds associated with Middle Sprayberry wells at the end of 2025 will be significantly higher than it was in 2024.

Speaker #3: So the answer will be, obviously, a lot more.

Speaker #7: Impact than we had in 2024, right? Because we had just drilled one well, and so really very few to no pods associated with it.

Speaker #7: I think it would be reasonable to expect that we would probably drill one to two more middle Sprayberry wells this year, plus the additional drilling that's been done off to our flanks by our offset operators.

Speaker #7: We could add some additional pods associated with those. So yes, the total number of pods associated with the middle Sprayberry wells at the end of 2025 will be significantly higher than it was in '24.

Jeff Robertson: 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?

Speaker #2: 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?

Michael Hollis: You bet. Now, you know obviously, Jack kind of mentioned it, when you are 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 ebbed and flowed in our direction. Then you look at second quarter, it is just a matter of timing of when we brought these wells on. Obviously, when you frack wells, you water pads out on either side. So you will 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. I think looking forward, that will be a pretty good guide for everyone from where we are to the endpoint.

Speaker #7: You bet. Now, and you know, obviously Jack kind of mentioned it. You know, when you're doing these pads, you do get a little bit of lumpiness.

Speaker #7: I think when you look at our yearly production guide, and the fact that, you know, Q1 we had a, you know, a pretty good month where everything kind of timing-wise, you know, ebb and flowed in our direction.

Speaker #7: And then you look at the 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.

Speaker #7: So you'll see some fluctuations quarter to quarter, and 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.

Speaker #7: And I think looking forward, that'll 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.

Michael Hollis: Again, we do not give quarterly guidance for that reason, but I think our yearly guidance is still solid. Yes.

Jeff Robertson: Thank you. Thank you for the question, Steven.

Speaker #2: Thank you, thank you for your questions.

Michael Hollis: You bet, buddy. Thank you.

Speaker #7: You bet, buddy. Thank you.

Speaker 2: Thank you. That does conclude the Q&A portion of our call and today's conference call. Thank you for participating. You may now disconnect.