Riley Exploration (REPX) Q3 2026 Earnings Call Transcript

DATE

Thursday, Nov. 5, 2026

CALL PARTICIPANTS

• VP Strategy and Investor Relations - Ben McQueen
• Chairman and CEO - Bobby Riley
• COO - John Suter
• CFO - Philip Riley

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TAKEAWAYS

• Oil Production -- 25.4 thousand barrels per day, an increase of 20% from the previous quarter driven by new well contributions and restored volumes.
• Total Production -- 42,000 barrels of oil equivalent per day, representing 23% sequential growth as midstream constraints in New Mexico eased.
• Cash Flow from Operations -- $111 million, a 75% increase versus the second quarter.
• Adjusted Net Income -- $56 million or $2.66 per diluted share, reflecting higher production volumes and improved natural gas realizations.
• Accrual Capital Expenditures -- $53 million, a 39% decrease quarter over quarter following a decline in drilling and completion activity.
• Debt Reduction -- $28 million reduction during the quarter, bringing the total debt balance to $245 million.
• Quarterly Dividend -- $0.42 per share, representing a 5% increase declared in October.
• Texas Oil Production -- 18.5 thousand barrels per day, driven by 12 gross wells turned to sales in Yoakum County.
• New Mexico Oil Production -- 6.9 thousand barrels per day, representing a 30% sequential recovery as third-party midstream operations normalized.
• San Andres Inventory -- 90 additional net development locations, identified through internal geological analysis and industry results in the fairway.
• Drilled-but-Uncompleted Wells -- 17.3 net wells, with 85% of the inventory located in the New Mexico Red Lake asset.
• 2027 Production Growth Guidance -- 30% to 40% year-over-year production growth, supported by the planned operation of two drilling rigs.
• Q4 2026 Oil Production Guidance -- 25.5 thousand to 26.5 thousand barrels per day.
• Q4 2026 Total Capital Expenditures Guidance -- $74 million to $86 million, reflecting the activation of a second rig and a full-time fracturing crew.
• Realized Oil Price -- $83.63 per barrel, excluding the impact of derivative settlements.
• Derivative Settlements -- $28 million realized loss, resulting from cash settlements on crude oil financial contracts.
• Lease Operating Expense -- $8.84 per Boe, including $11 million allocated to workover activities.
• Administrative Costs -- $2.27 per Boe, totaling $9 million for the third quarter.
• Credit Facility Liquidity -- $205 million undrawn, following an amendment that increased the borrowing base to $450 million.
• Annual Interest Savings -- $5 million estimated, following the retirement of $130 million in 10.5% Senior Notes in October.
• NGL Realized Price -- $5.08 per barrel, compared to negative realizations in the prior quarter.
• Rig Relocation Cost -- $100,000 to $150,000 per move, which management intends to minimize by focusing on multiwell pad development.
• Adjusted EBITDAX -- $117 million, compared to $80 million in the previous quarter.
• Net Operated Wells Drilled -- 8.6 net wells in the third quarter, with five gross wells in Texas and eight gross wells in New Mexico.
• Net Operated Wells Completed -- 7.9 net wells during the quarter, including 6.5 net wells in Texas.

SUMMARY

Riley Exploration Permian, Inc. (NYSEMKT:REPX) reported increased oil and total production volumes for the third quarter, driven by new development wells in Texas and a recovery from midstream constraints in New Mexico. Management initiated plans for an organic resource expansion into the San Andres formation at the Red Lake asset, projecting 90 additional net development locations. The company strengthened its financial position by retiring its 10.5% Senior Notes and increasing its borrowing base to $450 million. Strategic priorities for the fourth quarter include the activation of a second drilling rig and the completion of a significant drilled-but-uncompleted well inventory in New Mexico following the startup of new gas and water infrastructure.

• Chairman and CEO Bobby Riley stated, "We expect to add a second rig during the fourth quarter of 2026 and operate two rigs for a portion of the quarter, positioning us to carry that activity level into 2027."
• Management reported that the San Andres formation expansion could provide 90 additional net development locations across existing acreage without incremental acquisition costs.
• John Suter noted that the company secured a full-time fracturing crew and began working through the New Mexico drilled-but-uncompleted well inventory in October 2026.
• Philip Riley indicated that the retirement of $130 million in Senior Notes in October 2026 is expected to result in approximately $5 million in annual interest expense savings.
• CFO Philip Riley stated, "A significant amount of capital has already been invested ahead of the associated production response," regarding the potential to grow production into mid-2027 even in a lower commodity price environment.

INDUSTRY GLOSSARY

• BOE: Barrels of oil equivalent, a measure used to combine oil and gas volumes based on energy content.
• Bbls/d: Barrels of oil per day.
• Boe/d: Barrels of oil equivalent per day.
• DUC: A well that has been drilled but not yet hydraulically fractured for production.
• San Andres Formation: A geological shelf margin deposit in the Permian Basin targeted for oil and gas extraction.
• Waha: A natural gas pricing hub located in West Texas.
• NGLs: Natural gas liquids, including ethane, propane, and butane.
• EBITDAX: Earnings before interest, taxes, depreciation, amortization, and exploration expenses.
• Blinebry and Paddock: Specific geological zones within the Yeso package targeted for hydrocarbon development.
• Successful Efforts: An accounting method where only successful exploration costs are capitalized into the balance sheet.

Full Conference Call Transcript

Operator: Hello, everyone. Thank you for joining us, and welcome to Riley Permian Inc.'s Third Quarter 2026 Earnings Conference Call. After today's prepared remarks, we will host a question-and-answer session. If you would like to ask a question, press star one to raise your hand. To withdraw your question, press star one again. I will now hand the conference over to Ben McQueen, VP Strategy and Investor Relations. Please go ahead.

Ben McQueen: Good morning. Welcome to our conference call covering our third quarter 2026 results. I am Ben McQueen, VP of Strategy and Investor Relations. Joining me today are Bobby Riley, Chairman and CEO, John Suter, COO, and Philip Riley, CFO. Yesterday, we published a variety of materials which can be found on our website under the Investors section. These materials in today's conference call contain certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Potential drilling locations that will be discussed are based on management's internal estimates and are not proved reserves.

As of today, no proved reserves have been attributed to these locations. Whether and when they are drilled will depend on several factors, including commodity prices, capital availability, drilling and completion costs, regulatory approvals, results of offset and delineation activity, and other factors. Actual drilling activity may differ materially from these estimates. We will also reference certain non-GAAP measures. The reconciliations to the appropriate GAAP measures can be found in the supplemental disclosure on our website. I will turn it over to Bobby.

Bobby Riley: Thank you, Ben. The third quarter was an exciting quarter for Riley Permian as we continue to execute on the development program we have discussed throughout the year. Much of the activity completed earlier in 2026 translated into production during the third quarter, resulting in the significant step-up in volumes we had anticipated. Oil production averaged over 25,000 barrels per day, an increase of 20% from the second quarter and 38% from a year ago. Total production increased 23% sequentially to approximately 42,000 BOE per day. Importantly, we delivered that growth despite wells turned to sales coming in below the low end of our guidance range.

Those results reinforce our confidence in both the quality of our asset base and our ability to execute our development program efficiently. One area that I want to spend some time on today is an additional resource opportunity we have been evaluating at Red Lake. To date, our development activity at Red Lake has primarily focused on the Paddock and Blinebry formations, part of the Yeso package. We are now preparing to expand that activity into the San Andres. The San Andres itself is not a new development target for the region and has been productive for many years.

What we are evaluating is the opportunity to apply horizontal development across our existing acreage, consistent with how we develop the other formations across our assets. Over the past year, our technical team has been assessing the potential of the San Andres across our acreage. That work has included extensive geological and reservoir analysis, along with evaluating recent industry activity in the San Andres across and around our position. We believe that combination of internal technical work and encouraging industry results has given us conviction to begin allocating capital to the San Andres, with initial development planned for the second quarter of 2027 and initial production results later in the year.

The San Andres potentially provides approximately 90 additional net development locations across our acreage. Importantly, these additional locations are within the acreage we already own, adding potential inventory without incremental acquisition cost. Our current plan includes six San Andres wells during 2027, which should allow us to begin evaluating the opportunity through our own development results. Additionally, the infrastructure environment in New Mexico has materially improved. The WaterBridge water handling agreement went into service in September, and the new Targa gathering and high-pressure trunk line system was placed in service in October. Together, these projects provide additional water handling capacity and gas flow assurance to support increased development in our New Mexico acreage.

That progress is important as we move into the next phase of our development plan. Over the past several years, we have significantly expanded our inventory position while investing in the infrastructure necessary to support a large development program. During 2026, we increased activity, and the benefits of that development program became evident in our production results. As we enter 2027, we believe we are positioned to continue that progression. While we are not providing formal 2027 guidance today, I do want to provide an early preview of our plans for next year.

We expect to add a second rig during the fourth quarter of 2026 and operate two rigs for a portion of the quarter, positioning us to carry that activity level into 2027. Based on prevailing commodity prices and market conditions, we plan to run two rigs throughout 2027. As always, we will continue to monitor the environment and retain the flexibility to adjust any activity as conditions warrant. Our planned activity includes the development across both of our core assets. At Red Lake, the improved infrastructure backdrop allows us to increase development activity across the Paddock and Blinebry, while beginning initial development of the San Andres.

At Champions, we expect to continue developing the remaining high-quality inventory that has continued to generate strong results. Based on this planned activity, we expect another year of meaningful production growth. While our 2027 planning process is still ongoing, our current outlook is for oil and total production growth of 30%-40% year over year. We expect to provide formal 2027 guidance in March of 2027. We're excited about the progress we made this quarter, and more importantly, the position we have built heading into 2027. I want to thank our employees for their continued hard work and execution.

We have asked a lot of the team this year as we have increased activity and grown the business, and they have continued to deliver. I'll now turn the call over to John.

John Suter: Thank you, Bobby, and good morning. I'll cover our third quarter operational results, progress across Champions and Red Lake, and the work underway as we move through the fourth quarter and into 2027. As always, I'll begin with safety. Safe and reliable execution remains the foundation of how we operate, particularly as we manage a larger development program and growing infrastructure footprint. During the third quarter, we reported a total recordable incident rate of zero and delivered 95% safe days. During the third quarter, we drilled 13 gross or 8.6 net operated wells, completed nine gross or 7.9 net wells, and turned 12 gross or 11.9 net wells to sales.

All the wells turned to sales during the quarter were in Texas. Year to date, we've drilled 54 gross operated wells, completed 40, and turned 35 to sales. We ended the quarter with 25 gross or 17.3 net drilled uncompleted wells. Approximately 85% of those DUCs are in New Mexico, and we currently plan to complete that inventory over the next two quarters. Production results demonstrate the impact of all that activity. Oil production increased 20% quarter-over-quarter to 25.4 thousand barrels per day, while total production increased 23% to 42,000 barrels of oil equivalent per day.

At Champions, oil production increased 17% sequentially to 18.5 thousand barrels per day, primarily reflecting the contribution of new wells brought online during the year. At Red Lake, oil production increased 30% to 6.9 thousand barrels per day, despite no new wells being turned to sales during the first nine months of the year. The increase at Red Lake primarily reflects the return to more normal operations following the third-party midstream constraints we experienced during the second quarter. Last quarter, we said the June exit rate provided a better indication of our second half starting point than the second quarter average.

Third quarter results support that view, as shut-in volumes returned and Texas wells completed earlier in the year contributed to production. The growth reflected multiple factors, including restored production, new Texas wells, and continued optimization of the existing asset base. Our Yoakum County asset remained the primary driver of development and production growth during the quarter. We turned 12 gross wells to sales in Texas, compared to seven gross wells completed during the period, as activity completed earlier in the year converted to production. That is an important part of the story. During the first half of the year, we invested in drilling, completions, facilities, and takeaway capacity to support a higher pace of development.

In the third quarter, much of that work began translating into production. Champions' high working interest, established operating footprint, and more mature infrastructure continue to give us flexibility in how we sequence activity and respond to changing conditions. During the quarter, we also selected a number of Champions wells for targeted chemical treatments. Those treatments had limited impact on third quarter volumes because of their timing, but our current forecast reflects approximately 15% higher fourth quarter production from the treated wells. This is another example of using lower-cost optimization work to create incremental production and improve recovery from the existing asset base.

At Red Lake, our focus during the quarter was on preparing the asset for increased completion and development activity. Importantly, oil production also continued to recover from the second quarter midstream constraints, increasing approximately 30% sequentially, despite no new wells being turned to sales. During the quarter, we drilled eight gross New Mexico wells and completed two, but did not turn any new Red Lake wells to sales. That sequencing was intentional. As discussed last quarter, we've been coordinating completion activity with the availability of gas, water, power, and supporting field infrastructure. We made important progress on those infrastructure needs during the quarter and shortly thereafter.

WaterBridge began supporting the development program in mid-September, and Targa began taking volumes on its new high-pressure line in October. With that additional takeaway capacity now available, we have secured a full-time frac crew and begun working through the New Mexico DUC inventory while continuing to drill new wells. This increased completion activity will contribute to higher CapEx in the fourth quarter, with the production impact expected to begin toward the end of the quarter and continue into the first quarter of 2027. On water, the WaterBridge arrangement provides additional disposal capacity to support increased development.

While third-party disposal carries a higher cost than our own system, we believe that incremental cost is a favorable trade-off for the additional capacity and development flexibility it provides. We're also continuing to invest in company-operated water infrastructure, including additional saltwater disposal capacity, gathering lines, pumping capacity, automation, and related field facilities. Our objective is to utilize a combination of company-operated and third-party capacity to provide a flexible and reliable water system as development activity and produced water volumes increase at Red Lake. Looking ahead, our priorities remain straightforward. First, we will continue to operate safely and maintain the discipline required to manage a higher level of activity.

In Texas, we will continue converting the investments already made into production while addressing the oil, gas, and water infrastructure needed to support the current development pace. In New Mexico, we will begin to see the impact of the DUC inventory as gas and water takeaway systems are now operationally ready. The sequencing is deliberate. We began completing our DUCs immediately after Targa and WaterBridge commenced initial operations. That production impact will begin to be seen toward the end of Q4 2026 and into Q1 2027 as those wells are turned to sales. Finally, we are preparing for a larger 2027 operating program.

The third quarter demonstrated what the business can deliver as operational constraints ease and prior capital begins converting into production. Looking forward, we're preparing for a two-rig development program and further infrastructure build-outs that will accommodate meaningful Red Lake growth. Our focus from here is execution, maintaining safe operations, bringing infrastructure online, converting DUCs efficiently, and ensuring that capital translates into production and cash flow as quickly as practical. I'll now turn the call to Philip.

Philip Riley: Thank you, John. Cash flow from operations was $111 million, 75% higher than in the second quarter, or $222 million year to date, 50% higher than the same nine-month period in 2025. Third quarter accrual CapEx decreased 39% quarter-over-quarter to $53 million, mostly in tandem with the decline in D&C activity. Cash CapEx was $66 million, as payments for second quarter's higher activity flowed through the third quarter. Year to date, accrual CapEx is $187 million, and cash CapEx is $165 million. We paid $8.4 million in dividends during the quarter, and we had zero buybacks. With excess cash, we reduced debt by $28 million to $245 million. Quarter-end total shares outstanding, including unvested shares, were 22.2 million.

Year-over-year, debt is down by 35%, and shares outstanding have increased by less than 1%. Subsequent to quarter end, we drew on a revolver to retire our 10.5% Senior Notes at par for zero net change in debt balance. We estimate approximately $5 million in annual interest expense savings. Last week, we completed an amendment to our credit facility, upsizing the borrowing base and elected commitments to $450 million, allowing for $205 million of undrawn liquidity. We also extended the maturity to October 2030. Stepping back, we've demonstrated that growth and financial discipline are not mutually exclusive.

Over a three-year period, we've increased oil production by more than 80%, while reducing total debt by nearly 40% and limiting share count growth to 10%. We're scaling the business while improving the balance sheet and managing dilution. Now, a few comments on forward guidance and capital allocation. Bobby and John described the additional activity for the fourth quarter. That drives an increase in CapEx for the full year relative to previous guidance. We forecast a small amount of incremental production volumes in the fourth quarter, while added volume should materialize more meaningfully in the first and second quarters of 2027.

Additionally, while annual results remain an important measure of performance, given the pace and timing of our growth, we're increasingly focused on the progression of the business from quarter to quarter. In periods where capital investment precedes the associated production, calendar year comparisons do not fully capture that growth trajectory. We've added several new charts on pages 11 and 12 of our investor presentation that shows this actual and forecasted progression on a rolling quarterly basis, and we think they tell a compelling story. As we think about capital allocation, we're focused on creating long-term value on a per-share basis.

We have a deep inventory of attractive development opportunities, and under current market conditions, we believe investing in that inventory is our most compelling use of capital. At the same time, we'll retain flexibility with the pace of investment. As Bobby mentioned, we'll evaluate against commodity prices, the broader market and economic backdrop, full-cycle project returns, and our balance sheet goals. Our objective is to fund the development program from internally generated cash flow while maintaining a strong balance sheet. Importantly, that flexibility does not necessarily mean giving up the growth already underway. A significant amount of capital has already been invested ahead of the associated production response.

Even in a meaningfully lower commodity price environment, we believe we could materially reduce CapEx while continuing to grow production into the middle of next year, then moderate activity as needed to maintain a more balanced cash profile. Thank you all for your attention today and for your interest in our company. Operator, you may now turn it over for questions.

Operator: We will now begin the question-and-answer session. Please limit yourself to one question and one follow-up. If you would like to ask a question, please press star one to raise your hand. To withdraw your question, press star one again. We ask that you pick up your handset when asking a question to allow for optimum sound quality, and if you're muted locally, please remember to unmute your device. Please stand by while we compile the Q&A roster. Your first question comes from the line of Derrick Whitfield with Texas Capital Bank. Your line is open. Please go ahead.

Derrick Whitfield: Thanks, and good morning, and thanks for taking my questions, and also thanks for the early outlook on 2027. With respect to your outlook, there's seemingly a disconnect this morning in the value of your growth trajectory in both the $70 and $90 scenarios. As it relates to your CapEx assumptions, could you speak to what you've embedded in the estimates from an activity and inflation perspective, and if you've embedded any efficiency gains in those projections?

Operator: One moment, please. We are experiencing technical difficulties. Hold while we work to fix that.

Philip Riley: Okay. I'm going to keep going here. We've got the second rig. We've got that contracted with some good flexibility. Only about a quarter of the year is contracted, so that's a small amount out of the total. Frac crews should be coming in as well, but as we think about the different prices, we've shown you an illustrative range here of $70-$90. Currently, we're above $90 in the market, right about there. We show very material growth there at that level. That corresponds to what Bobby was describing as that kind of 30%-40% year-over-year growth. You can see it on a sequential quarterly basis.

Then down at $70, we just show an illustrative range of what we think we could do. That grows pretty meaningfully through the second quarter of next year and then slows down moderately. Both of those are just illustrative. We still got to finish that off with our board, and then, like Bobby said, we'll come back in March and give you more confirmed guidance. Very quickly on the efficiencies, we're really going to be conservative here on how we're modeling that. We hope to realize some, but haven't relied on it too much. Then inflation, we're assuming a modest amount of inflation, some of which we're seeing in the tangibles, maybe 10% or so.

I think some of that's obvious. You've heard it from others, Derrick, the casing, the diesel, some of the chemicals and such. Anything else I'm missing, John?

John Suter: No, I think you've hit it right on the head. 10% built into our cost forecast, but really, we believe we're offsetting any kind of cost increase from diesel and casing, with various things, other synergies that we're doing. So we think that we are actually realizing a net effect of zero for inflation. As you mentioned, we're only contracted for about 25% of the wells we plan on drilling next year, and only about 10% of the completions, that we'll be bound to do. So we have a tremendous amount of flexibility to deal with various market conditions, or any kind of results we might see. So, great amount of flexibility.

Derrick Whitfield: Great. So definitely tremendous flexibility, very conservative assumptions. Shifting over to the San Andres with my follow-up. Clearly an important interval for you guys as you think about the resource expansion opportunity given the growth outlook. Based on your extensive review of the subsurface and industry results, could you speak to how the interval compares to the Blinebry and Paddock intervals, and what you're expecting from an EUR and cost perspective?

John Suter: Yeah. So, we view this as just an additional interval within a co-developed multiple bench resource. The Paddock and Blinebry are still going to be the foundation of the development. The San Andres is just slightly shallower, but again, allows us that benefit of using existing infrastructure that we already control, and doing this on acreage that we already have. So, it's a big benefit. We were going to start full field development. We were, a year ago or so, building that infrastructure so that we would be ready, and we knew this was already a target for vertical wells, and just decided that it would be so much easier to co-develop it with the Yeso.

And so that's the path our technical team started studying, and then got to the point where we feel comfortable adding these potential locations. I don't believe we're ready yet to talk about EURs, but again, we feel comfortable with our experience in Champions with the San Andres. This is 80 miles away and same zone, but there's always still differences in rock quality and things we want to investigate with our own program. But we're excited about what we've seen so far from public data and our view of industry activity within our own fairway. So, feel really good about it.

Derrick Whitfield: Fair enough. It seems very encouraging. Thanks for your time.

Operator: Your next question comes from the line of Neal Dingmann with William Blair. Your line is open. Please go ahead.

Neal Dingmann: Morning, Bobby and team. Bobby, I just want to say, yeah, I think this plan, ops plan of yours makes total sense here. My question is around the plan, as well as Derek asked, and could you remind me, with this two-rig consistent plan, how many wells we are talking about you might be able to knock out in, I do not know, a year or so? I think you mentioned this earlier, but I am assuming now you believe you will have more than ample takeaway for this type of growth.

John Suter: Yeah, we will. Let me get the number that we are looking at right now.

Philip Riley: On a net basis, it is about 90 wells, more or less.

John Suter: You are right. The takeaway allows us to get this program underway, so we are pretty excited about it.

Neal Dingmann: If I could ask one more on that one, will the two rigs remain in kind of the same focused areas, or how much will you move those two rigs around?

John Suter: Yeah. In general, we will have one rig in Champions and then one rig moving over to New Mexico. It will probably move over there about in, oh, late first quarter, I would say. We want to really focus on completing our DUCs in New Mexico first. That will allow us to increase production there and start filling our infrastructure as we get a little bit ahead in Champions, and then move back over and start handling some of these large multi-well pads in New Mexico.

Neal Dingmann: Got it. Then second, if I could, just on the expansion initiatives across the Red Lake asset, could you talk about, I really think there is some interesting upside there. Could one of you all talk about just the various upside? Are you talking about just the one incremental formation, or how much inventory upside could we be referring to?

John Suter: From an inventory standpoint, we're going to be drilling the Paddock, Blinebry, and as we get it permitted, the San Andres. We initially put 90 net wells out there for the San Andres. We have not evaluated all of the San Andres yet, so we believe there's potentially additional upside there, as well as other formations. As far as our 2027 plan goes, we'll be doing all three layers, again, with some pretty decent-sized pads. As you've noticed, our production occasionally comes on in waves.

When you do some of these larger pads of six, seven, eight wells, again, you have to wait until all those wells get fracked, all those wells get drilled out before you actually bring on that pad. Especially in New Mexico, I think you're going to see, again, it be coming on in waves. Again, we're already starting completion of DUCs. We just finished fracking about our first 10 of the 24 New Mexico DUCs. Again, we'll start soon drilling those out, and then there's usually a bit of a flowback period before you get stronger oil and gas. That's why, even though we've already started, you won't see any decent impact from those particular wells until early January.

Neal Dingmann: Perfect. Thank you all.

Operator: Your next question comes from the line of Jeff Robertson with Water Tower Research. Your line is open. Please go ahead.

Jeff Robertson: Thank you. Good morning. John, on the San Andres, how much do you still need to understand with respect to how best to complete horizontal wells in the zone in Red Lake?

John Suter: Yeah, I think we've learned quite a bit in Champions about the San Andres in general. There's still differences in reservoir character, the particular depletion history in New Mexico may be slightly different than Texas fluid properties. So we'll have to zoom in on our completions and learn from these wells. Obviously, we use that Champions experience to start with, but then we'll be tweaking as we go to handle the various technical differences and what we see of how they perform.

Jeff Robertson: Do you think that the best approach will be to co-develop the San Andres with the Blinebry and Paddock on pads?

John Suter: Oh, absolutely. Even though they are separated geologically with a barrier in between, we just want to make sure that all of our frac energy is contained in the San Andres as we complete it, as well as our other intervals. So it makes so much more sense to co-develop those. You'll get the best frac job in each interval. If you think about rig moves costing like $100,000-$150,000 per rig move, every time we stay on one pad and avoid a rig move, we're doing zipper fracking, again, for that best frac possible. It just really starts adding up to a lot of money besides just the technical applications.

Jeff Robertson: Thank you.

Operator: As a reminder, if you would like to ask a question, please press star one on your telephone keypad now to raise your hand. Your next question comes from the line of Nicholas Pope with Roth Capital Partners. Your line is open. Please go ahead.

Nicholas Pope: Good morning, everyone.

Speaker 9: Morning.

John Suter: Morning.

Nicholas Pope: Curious, you took all the fun geology questions. Curious with the startup of the gathering of midstream assets and this contract with WaterBridge for water handling, what that means for the trajectory for operating and gathering costs going forward over the next years as you kind of expand and grow production? Is it going to be a meaningful difference with current kind of unit rates on production?

John Suter: No, I don't think so. On the gas side, it should be similar. On water, there certainly is an increased cost when going to WaterBridge. Again, we view that as a favorable trade-off, even though that costs a little bit more money, it allows us to develop at our own pace, not to worry about that. We don't have to sequence things quite as much as we used to, because we have that capacity now. But we also work hard to give WaterBridge the minimum that we have to and fully use our own saltwater disposal system, just because it's substantially less expensive from those investments that we've made in the past.

So, we look at that as really kind of a combined rate in our own head of fully utilizing our own, and then giving the excess to WaterBridge.

Philip Riley: I'll just follow up back on the Targa line. We've always said this is primarily about flow assurance, and so that's what's manifesting or allowing this increase in activity for John's operations here. At the same time, we do hope to get better NGL yields, so this will be much newer equipment and plants it'll be running through. We think that ultimately shows up in better NGL yield, and those command the better value there. Some of it can be slightly higher fee, but we hope to offset that. This quarter, just for the avoidance of doubt, this quarter we had some higher gas realizations.

That was not due to this specific infrastructure, but rather some of the changes you saw on the downstream residue gas line egress that improved Waha there and allowed us to absorb the fees with the gas and the NGL both. Gas prices are volatile, as you know. They're looking decent at the moment, weaker again next summer, and that probably will continue to be volatile.

Nicholas Pope: Yeah, I appreciate that. If we could dig a little bit more into the new inventory and what y'all are looking at with San Andres. The 90 wells that y'all are looking at that you're adding to potential inventory is, I guess, what are the criteria like in how y'all are defining what you're comfortable adding into inventory? Is it just proximity to near-term drilling and plans that you have on the deeper formations? I'm just more curious, I guess, how y'all judged the criteria to kind of tentatively add that into the inventory.

John Suter: Yeah, let me preface that with just saying, look, our team did a significant amount of technical work over the past year, everything from geologic reservoir analysis, again, looking at the legacy vertical production depletion, looking at recent horizontal activity. So, there was a lot of work put into that, especially oil in place mapping was a significant. I'd say the oil in place mapping and depletion were kind of significant things that helped us figure out where to attack first, looking at some of your best opportunities first. Then you are exactly right, proximity to known resource, starting with a conservative spacing of four wells per section.

We think that's the key is basically starting with close proximity and knowing what your technical information is leading you towards, and then let our own performance on our own operated wells kind of help dictate how and where we accelerate the program to.

Nicholas Pope: Got it. That's very helpful. Fun stuff. Appreciate the time.

John Suter: Thank you.

Operator: Your next question comes from the line of Jeff Robertson with Water Tower Research. Your line is open. Please go ahead.

Jeff Robertson: Thank you. A question on the production profile as Red Lake becomes a bigger part of Riley's mix. Will that have an impact on the production mix between oil, gas, and NGLs?

Philip Riley: Yeah, it might be a little bit gasier. I think at the moment, Red Lake is gasier as a function of it being older. Sorry, a larger amount of the mix is some of the old legacy vertical wells. New wells are going to be oilier, and so that generally will make that field itself oilier. As for the overall corporate mix, it might get slightly oilier there, but not a material amount, Jeff. This is still an oily field, oil-driven play, and economics will continue to be oil-driven with oil revenue.

Jeff Robertson: Philip, on oil revenue, can you talk a little bit about how you're thinking about hedging volumes? I know the hedged volumes based on the preview outlook you have for 2027 goes down pretty significantly from what has been hedged in 2026.

Philip Riley: Yeah. With hedging, we begin with the lens of risk management, and that is a function of what our capital structure looks like and what our capital obligations are. If we look back 18 months ago, we were sitting here telling you how we were buying an acquisition with 100% debt, tightening our belt to get that done, and at the same time, we had this large nine-figure gas midstream project that we were developing. This was prior to selling that to Targa. It was a different set of capital obligations, and so we had more to hedge and to manage the risk.

At this point, we have a very healthy balance sheet, and that really drives some of our thinking. We try to be careful not to speculate. I think we're quite hedged at the moment. For the coming remaining months of the year, we're a little under 60%. First quarter, it's looking plus or minus 50% of total volumes there. Then, yes, does decline through the year, as you know, pretty materially there. When you compare us to others, I think we're very much in line. We're going to be more hedged further out on 12 to 18 months versus the large caps versus small caps, I think we're very similar.

What I'd end with here is that it continues to be a very volatile world. Look at the last 24 hours. The front month is still We still have quite a bit of backwardation over a three to five-year period, so we want to be careful not to lock in too much. You can't hedge service costs. Typically, you can't hedge your LOE and your capital costs, and so we want to be mindful to be ultimately price takers on our revenue and match that with our costs and capital.

Jeff Robertson: Thank you.

Operator: We have reached the end of the Q&A session. This concludes today's call. Thank you for attending. You may now disconnect.

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