Riley Exploration Permian Aktie

Good day, everyone, and welcome to the Riley Exploration Permian Inc. Second Quarter 2026 Earnings Call. This call is being recorded. At this time, I would like to hand the call over to Mr. Philip Riley, CEO. Please go ahead, sir.

Good morning. Welcome to our conference call covering our second quarter 2026 results. I'm Philip Riley, CFO. Joining me today are Bobby Riley, Chairman and CEO; and John Suter, COO.

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. We'll also reference certain non-GAAP measures. The reconciliations to the appropriate GAAP measures can be found in our supplemental disclosure on our website.

I'll turn the call over to Bobby.

Thank you, Philip. Earlier this year, we outlined our strategy to accelerate development activity and production growth in 2026, and we continued advancing that strategy during the second quarter. Our second quarter development program was the most active in Riley Permian's history. This heightened level of activity, together with production enhancement projects across both assets helped us deliver oil production near the high end of our guidance range and a June oil production exit rate of 24,400 barrels per day. While the quarter showed 5% sequential oil growth on average, we view the June exit rate as a better representation of the underlying momentum in the business and the foundation for the growth we expect during the second half of the year and into 2027.

Importantly, a significant portion of the operational activity completed during the first half of the year has yet to be fully reflected in production. As a result, based upon our current outlook, we are increasing our full year oil production guidance, which now calls for approximately 30% year-over-year oil production growth. We forecast our largest increase of the year during the third quarter when we expect oil production to increase more than 20% sequentially. Our strong second quarter results were achieved despite midstream constraints during April and May that required temporary well shut-ins and reduced oil production by approximately 2,000 barrels per day. The disruption reinforces the strategic importance of the new high-pressure gathering and trunk line system being constructed by Targa, which is expected to enter service during the fourth quarter.

While these disruptions limited the quarter's full potential, our underlying growth plan remains on track. The production growth we expect over the coming quarters reflects both the activity executed during the first half of the year and the development activity still ahead of us. As we bring those volumes online, we expect higher production to support stronger cash flows generation and improved returns on the capital we've invested. At the same time, continued infrastructure development in New Mexico is expanding our opportunity set and helping unlock a larger portion of our inventory for future development. We are encouraged by the progress made during the first half of the year and remain focused on safely and efficiently converting that activity into production growth during the balance of 2026 and throughout 2027.

I'll now turn the call over to John Suter.

Thank you, Bobby, and good morning. I'll cover our operational results for the second quarter, the progress we are seeing across both of our core development areas and how we are positioning the business for the second half of '26 and beyond.

As always, I'll start with safety because safe and reliable execution remains the foundation of everything we do. During the second quarter, operations reported a 0 total recordable incident rate, and we delivered 98% safe days. That is a strong result in any environment, but especially important given the level of activity our teams managed during the quarter. Development activity increased during the second quarter and was primarily focused in Texas. On a net basis, we drilled 19.9 wells, completed 17.3 wells and turned 13.9 wells to sales. Total capital spend on an accrual basis was $87 million for the second quarter. Drilling and completion capital expenditures were $70 million, which was in line with the midpoint of guidance. Infrastructure and other expenditures were approximately $17 million compared to the guidance midpoint of $12.5 million.

The variance in infrastructure and other capital expenditures can primarily be attributed to accelerated development and bringing forward costs that would otherwise have been realized in the second half of 2026 or later. Turn-in lines came in below guidance for the quarter, primarily due to delays in third-party infrastructure needed to support the higher development pace in Texas. Those projects were related to gas, oil and water takeaway and were a driver of the higher capital spend. The production impact in the second quarter was minimal because these wells were scheduled to come online later in the quarter. They've all since been turned in line, and we expect to see the production contribution again in the third quarter.

From an execution standpoint, the quarter was very strong. In Texas, the drilling team delivered 12 gross wells plus 1 SWD, improved average lateral footage per day by 19% and reduced drilling cost per lateral foot by 7.5% compared with 2025. We also set new Yoakum County records for both 1-mile and 1.5-mile wells. These were not isolated well results. They reflect broader improvement in planning, pad execution, bit and BHA selection, directional performance and day-to-day coordination across the drilling organization. New Mexico drilling also made a meaningful step forward after deferring development activity in 2025 while waiting on infrastructure build-outs. Compared with the 2023 and 2024 combined campaigns, we increased average lateral feet per day by 67% and reduced average drilling cost per lateral foot by 32%. We also successfully executed the first 1.5 mile lateral in Red Lake, which is an important milestone for the asset.

The combination of faster drilling, lower cost per lateral foot and more complex well designs reflects the operational knowledge we've built over time and gives us confidence in the repeatability of future development. Another important point is that we have continued to mitigate operating cost pressures through disciplined execution even as several major input costs have moved against us. Total LOE increased $5.4 million quarter-over-quarter with approximately $1.9 million coming from recurring LOE and $3.5 million from workover expense. That increase came during a period when we were also absorbing pressure from higher water disposal needs, steel and tubular costs, diesel, power and service activity. Importantly, though, a meaningful portion of the workover spend was intentional and value creating. Approximately $2.3 million of WOE was associated with production maintenance and optimization projects that added roughly 700 barrels of oil per day of incremental production.

We view that as one of the lowest cost sources of production growth available to us. So while operating costs were up quarter-over-quarter, a large portion of that increase was tied directly to projects that improved production, enhanced run time and created strong returns. At the same time, the team continued to offset broader cost pressure through field level efficiency gains, vendor optimization, chemical program improvements and lower cost workover execution. There are a few specific examples worth highlighting. In Texas, we successfully trialed 10 surface acid and chemical treatments to avoid costly downhole interventions. Those treatments saved approximately $210,000 per intervention, which represents roughly a 75% reduction compared with the alternative downhole work. We plan to expand this program more broadly considering the promising results. With a conservative estimate of 40 of those treatments per year, that could correspond to $8.4 million in annual savings.

In New Mexico, changes to the chemical program implemented in January are already showing an approximate 50% reduction in chemical costs. Better chemical surveillance and improved ESP run times are also helping reduce workover expenses. On the topic of Silverback, that acquisition has become a strong case study in the type of value we believe Riley can create inside our existing operating footprint. Since closing, we've created value in 2 primary ways: lowering the cost structure and increasing production. With Silverback properties, monthly per well workover costs have decreased by approximately 59%, driven primarily by fewer short runs and improved chemical program surveillance. On the production side, Silverback has materially outperformed expectations.

Through strategic workovers, return to production work, wellbore cleanouts, artificial lift optimization and conversion activity, production is now approximately double where the buy-side case projected it would be at this point, and that's been achieved with no new wells drilled. Despite the midstream-related shut-ins Bobby referenced, the underlying operating trend in the second quarter was much stronger than the quarterly average alone would suggest. Volumes were pressured early in the quarter, but as shut-in production returned, new wells came online and workovers contributed across both Texas and New Mexico, production improved materially in quarter end.

The broader takeaway from the quarter is that both our Texas and New Mexico assets improved across the areas that matter most operationally, safety, efficiency, cost and technical execution. In Texas, we continue to benefit from a more overall mature infrastructure footprint and very high working interest, which allows us to move quickly and efficiently. In New Mexico, we're continuing to prove that the asset can be developed with improving costs and cycle times, while we also work through the infrastructure sequencing required to unlock the full value of the acreage.

Looking ahead to the third quarter and the remainder of the year, our development sequencing is being influenced by the timing of the Targa pipeline. We are excited that the construction of the line is well underway. They've successfully completed a key river crossing and now are trenching, stringing pipe and welding the remainder of the line. The latest forecast projects the new Targa pipeline to be in service early in the fourth quarter of 2026. The full year activity schedule has been updated to reflect that timing by shifting some drilling and completion activity from Texas to New Mexico. Operationally, the way we are managing that timing is straightforward. We do not want to complete New Mexico wells too early and strand capital while waiting on gas takeaway. Instead, we are aligning completions with the expected pipeline in-service date and using the flexibility of the program to manage timing.

This is also why Texas remains important to the 2026 plan. Texas infrastructure is more mature today and those wells can generally be brought online sooner. We've also been preparing for a more unconstrained development model in New Mexico in ways that go beyond gas takeaway. Water handling is a key part of that equation. Our third-party disposal agreement with WaterBridge begins supporting the Red Lake development plan this year with the initial commitment period beginning in September. That solution does come at a higher per barrel cost than our own disposal system. So we do expect it to create some upward pressure on LOE over time. But the trade-off is very clear. Additional water takeaway gives us the capacity and flexibility to bring wells online at the pace our development plan requires. With it, we can accelerate development, improve cycle times and convert more of the Red Lake inventory into production and cash flow sooner.

In that context, we view the incremental disposal cost as a good trade for the development flexibility and long-term value it helps unlock. Putting it all together, the operational message for the quarter is positive. We executed safely. We improved drilling performance in both Champions and Red Lake in a highly active quarter. We continue to build the necessary infrastructure to support our asset development plans in Texas and New Mexico. Our production growth plan is on track.

As we move through Q3 and into Q4, we will remain disciplined. We will continue to prioritize safe operations, capital efficiency and timing wells to infrastructure. Champions gives us near-term flexibility and production visibility, while Red Lake gives us an expanded growth platform as the Targaline WaterBridge solution, saltwater disposal capacity and supporting field infrastructure come together. That combination positions us well for the remainder of 2026 and provides a stronger foundation for 2027 and beyond.

I'll now turn the call to Philip.

Thank you, John. I'll cover a few financial metrics very briefly before turning to our revised outlook. High oil prices drove operating cash flow 35% higher quarter-over-quarter to $64 million. Cash CapEx and other investments increased 153% quarter-over-quarter to $73 million. Free cash flow, which is calculated before changes in working capital and before acquisitions, decreased to $6 million this quarter. Year-to-date, free cash flow is approximately $30 million.

In addition to the CapEx activity that John described, we completed a very small acquisition in the Red Lake area for $2.4 million, yielding 4.0 net undeveloped locations for an average cost of $600,000 per location. We used $9.5 million of cash for dividends and buybacks. Quarter end principal debt balance increased by 11% or $26 million to $273 million as we drew on our credit facility to fund our cash uses this quarter. Please see our published materials for a wider discussion of results.

Now quickly on our power joint venture. Our first 10-megawatt merchant generation site was placed into commercial service midway through the second quarter, and we began selling into ERCOT's day ahead and real-time markets. The second site is finalizing commissioning, currently selling into real-time markets, while a third site is beginning commissioning. This project is very small scale relative to our core business, but we acknowledge the investor interest in the joint venture. Also, summer power prices are at multiyear lows following a surge in solar supply and new large load interconnections are stuck in the queue. But the long-term thesis remains an interesting option to monetize undervalued Permian gas.

Now a few comments on forward guidance. We plan for a reduction in development activity and accrual CapEx in the third quarter of 2026 compared to the second quarter, and we're guiding to $59 million of accrual CapEx. However, consider that second quarter cash CapEx was $18 million or 21% lower than accrual CapEx. So that cash dynamic could certainly flip in the third quarter as invoices roll in. Third quarter guidance at the midpoint for oil production is 25,600 barrels per day, 5% above June's level and more than 20% above the full second quarter level. For full year CapEx, we're increasing guidance at the midpoint by 12% or $26 million to $236 million. Roughly 1/3 of the increase is associated with upstream activity and 2/3 relates to infrastructure.

The upstream increase is primarily driven by increased drilling, partially offset by fewer completions. Our ratio of wells drilled to wells turned to sales this year is 1.2, implying we're carrying drilled but uncompleted wells into next year. Regarding the increase in infrastructure capital, 60% is associated with saltwater disposal projects with most of the balance related to oil gathering projects. Most of these are associated with our Champions project in Texas. Incorporating these updates, we're raising full year oil production volume guidance ranges by 2% to 23,000 barrels per day at the midpoint, corresponding with the over 30% year-on-year growth that Bobby mentioned at the start. Based on current forecasts and commodity prices, we forecast higher free cash flow in the second half of the year compared to the first.

Thank you all for your attention today and for your interest in our company. Operator, you may now turn it over to questions.

[Operator Instructions] Your first question will come from Derrick Whitfield, Texas Capital.

Congrats on a positive quarter despite the many headwinds you faced. I wanted to start with your outlook and some of the comments you made in your prepared statements. While I realize you're not providing 2027 guidance to date, the heightened activity of your 2026 capital plan and the potential of your workover opportunities at Champions seemingly places you on a stronger trajectory headed into 2027 than what was the case that you outlined in Q1. How would you frame the trajectory based on increased activity and the potential for additional workovers.

Derrick, this is Bobby. I'll try to start with that and then turn it over to the other guys. I mean I see us having a pretty steady pace of development. We have 1 rig running now continuously. So without any unforeseen hiccups in the current markets, I just think that we're steady as she goes is we're a growth company. We intend to grow production year-over-year, spend within our cash flow, reduce debt, pay dividends. So, I don't see anything too different next year than where we are today.

And then maybe just on the follow-up on kind of leaning in on Champions, if I could. What you're highlighting on Slide, I think it is 10 of your deck, seems exceptionally capital efficient in terms of growing production. How should we think about the depth of workover opportunities you have at Champions and how you plan to feather those into your development plans?

Yes. So we talked about -- during our prepared remarks about those 10 wells that we've trialed this quarter. I think we've done 19 of them overall. And I think that really that entire asset base, certainly all the horizontal wells as the case is needed, all could be potential candidates for that. So there's potentially a couple of years of inventory right there. And New Mexico, we've done some of this, but really, there's a lot more wells there to try this on as we grow. So I think we do have a good inventory of it. And like I said, that's pretty easy to feather in, but we'll continue to watch the results. Let me remind you, too, that most of this is very low decline as opposed to new wells that come on. So you also have the benefit of that from those barrels that are added.

Your next question today comes from Neal Dingmann from William Blair.

Maybe, Bobby, for you or Philip, just a little bit on capital allocation. Derrick asked around the growth, which I'm glad to hear that given your size, you're a growth company. Do you look at that sort of, call it, organic growth versus external M&A growth sort of externally from each other? I mean, if you grow it organically, does that -- is that going to limit how much M&A? Or maybe just talk about how you think about capital allocation for the 2.

I could start. I think about what's within our control versus what's not. We have a nice sized inventory of undeveloped locations. We can choose to develop those. That's what we're doing this year after building that up over the last few years. Those provide nice full cycle returns at current commodity prices. We're always opportunistically looking for acquisitions, but ultimately, that's out of our control. It was -- for the market in general, quite a quiet quarter in the second quarter, and I think that's rational given it's historically difficult to execute during times of high volatility for buyers and sellers to come together on an agreed price. We're certainly going to try to overcome that going forward. But in the meantime, we do have what we can control, which is this nice inventory to draw down.

Great point. And then just a follow-up on gas takeaway specifically. I know many peers have added -- I know you guys did some infrastructure work previously. Others out there have done some FT. I'm just wondering, again, is there still takeaway constraints for you all? Or -- and if there is other things that you're doing to continue to minimize that?

Yes, I'll take the first part of that. From a gas takeaway, like we said, we believe that Targa line will be in very early fourth quarter. Up until then, we do have some exposure on the New Mexico side. But again, here, it's already August, and we believe we do have some of that under control. So really, we just need to get to October 1, and we should be in good shape, we hope. And I'll hand it to Philip to talk about some of the FT type stuff.

Yes. When we talk about infrastructure constraints, I know it can be confusing given it permeates the discussion both within our micro situation and then the kind of wider macro industry in the Permian. What we've been talking about for our own project, Targa and such and what John was talking about is for wet gas, getting that out of a smaller region to the processing plants. And then what you see written about more widely and what other companies are discussing is arguably that dry gas, egress out of the Permian to the Gulf Coast and other markets. I know we've all seen a couple of large projects come on in the last 2 months and price has rebounded, the Waha price very quickly and very significantly, I think, more than people anticipated.

I'm not going to pretend to be an expert on this, but I'll regurgitate a bit what I've read. And it seems to be a combination of some really hot weather at the same time. So power burn was bigger than expected. That helped some of that price. I think you had some of the gas shut in from how bad April and May was. And so that should be coming back. The pipes, those new projects appear to have filled up very quickly and yet price remains pretty high. So we'll see how long that lasts. The forward curve has the price weakening again, albeit better than it was a few months ago. We're optimistic on that. We do what we can. We put on some Waha hedges recently with that better price. We wouldn't be surprised to see it weaken just with historical patterns, associated gas in the Permian increased drilling with $70-plus WTI. But we shall see a lot of the bigger power projects have been slower to come on, and so some of that burn has been slower. But that's kind of our point of view at the moment.

[Operator Instructions] Next up is Jeff Robertson, Water Tower Research.

John, you talked about the production performance on the Silverback assets since the early assumptions. Has most of the heavy lifting been done to add production to or enhance production at lower cost on those assets through some of the workover activity that you all have performed?

I think we've picked off some really obvious ones. I think there's certainly more work to do. We haven't even tried pushing some of this surface acid kind of chemical injection projects over in New Mexico, not many of those. And so we think there's still a lot of running room with that. But again, we feel really proud of that since we haven't even drilled any wells there yet. And really, the reason for that is just it's not because those aren't great wells. We're kind of starting within our infrastructure and working our way out just to be more capital efficient. But we've done some great work over. So we're pretty excited about what that will mean for our drilling opportunities over there as well.

I guess as you think about 2027, Philip commented that free cash flow is going to expect it to increase in the second half of the year. Can you -- either Philip or Bobby, can you share some perspective on how you're thinking about free cash flow and with respect to returning cash to shareholders, the trade-offs between repurchasing shares through the authorization and the dividend?

Yes. I think our main focus is to remain flexible with having all those choices in front of us in any given quarter. I mean, obviously, we've been paying dividends. We've been growing our dividend year-over-year. So I expect that trend to continue. I think some of the money that we're spending this year and early into next year is going to translate into higher production, which depending on oil price, it's going to be very positive for us. But we just have the choices. Stock buybacks seems to be one of them that we've used it, and we'll use it if we feel it's appropriate. I don't see us ever going to any type of special dividend or anything like that. We'll just kind of continue as we've been going. Our debt right now at 1.0x leverage is reasonable. We can continue to pay that down and will as a potential source of that use of that cash. I don't know, Philip, what do you think?

I'd echo that, and I'll repeat what I've said in the past, which is we like the idea of growing free cash flow faster than the dividend in that we've had consistent growth of the dividend. We see that continuing and not changing the slope of that increase. We've got the buybacks as a new tool. And so I think about it as what is the excess free cash flow above and beyond the dividend and then allocating that between debt and buybacks. Like Bobby said, debt is at a comfortable level. You could pay it down more and that creates a little more flexibility for doing acquisitions.

It just gives you that much more leeway on how to finance an acquisition should you come across additional deals where sellers prefer cash instead of equity. And we know equity markets can be tough. And the more options you've got to not have to use that gives you more flexibility there. So we feel good about it looking at the forecast and excited for the next 2 quarters and the year ahead.

Your next question is Noel Parks, William Blair.

Noel Parks with Tuohy Brothers. I was wondering if you could maybe just refresh my memory on sort of the back story of the more complex well designs you mentioned. And I was just trying to recall whether that's sort of like just geo-steering to stay in zone or more like U-shaped lateral designs for when you don't have the adjacent sections to extend into.

Yes. No, what I meant by that was as we're starting to drill quite a few wells per pad, we're having to back drill quite a bit, do different things to fit in all the laterals that you have quite a few 5, 6 wells in a 320 acre units. So also working around fields that have vertical wells in it. So it just makes a little bit more complex designs. We would love to be able to do some of those turns and different types of wells that make a lot of sense in deeper horizons. But I remind you that in New Mexico, we sit at about 3,500 feet and in Texas, about 5,500 feet. So there's not really a lot of options at that shallow depth for those kind of designs, mostly just speaking to having to back drill and do some other wellbore avoidance.

And just could you just sort of maybe update us on where things stand as far as just your well spacing in New Mexico?

Yes. We are studying that right now. We generally will have 2 wells in the Paddock and maybe 3 in the Blinebry. We're also taking a look our technical team now of the San Andres and the Lower Blinebry. We think that there's upside there in the future. We're studying that now and hope to have some updates in the coming quarters of what our plans are there.

At this time, there are no further questions. That does conclude our question-and-answer session. It also concludes our conference for today. We would like to thank you all for your participation. You may now disconnect.

Good day, and welcome to Riley Exploration Permian First Quarter 2026 Earnings Conference Call. [Operator Instructions] Please note that this conference is being recorded.

It is now my pleasure to introduce your host, Philip Riley, our Chief Financial Officer. Sir, you may begin.

Good morning. Welcome to our conference call covering our first quarter 2026 results. I'm Philip Riley, CFO. Joining me today are Bobby Riley, Chairman and CEO; and John Suter, COO.

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.

We'll also reference certain non-GAAP measures. The reconciliations to the appropriate GAAP measures can be found in our supplemental disclosure on our website.

I'll turn the call over to Bobby.

Thank you, Philip. In March, we announced that Riley Permian would accelerate growth in 2026, which was a natural result from our multiyear positioning, including deliberate inventory expansion and infrastructure readiness. Our 2026 development plan was designed when the WTI spot price and 1-year forward price were in the $60 range, and we saw meaningful value creation potential at those price levels. Since then, the oil supply picture and price outlook have changed completely, we have increased confidence in achieving our planned targets and the corresponding value creation potential has increased significantly.

Our first quarter results provide an initial round of momentum for the year ahead. We executed well, delivering production exceeding the high end of guidance while spending less than the low end of our capital guidance range. With our excess capital, we reduced debt by $8 million and returned $12 million to shareholders through our dividend and share repurchases.

Our first quarter activity levels increased materially over fourth quarter 2025 levels and second quarter activity will surpass first quarter, setting up for an accelerated growth. We forecast production growth continuing for each quarter through the year, culminating with full year growth of 30% at our new midpoint guidance levels.

As we look further out to next year, we see the potential to grow production 10% year-over-year with only a 5% increase in CapEx, at least as one scenario being considered. We believe this could be achieved given the wave of second half 2026 volumes being generated. We have confidence in achieving this growth through accelerated development of both of our assets.

In New Mexico, Targa has progressed on the engineering and design for the high-pressure trunk line to their processing plants, which will begin construction upon final regulatory approval. The project timing remains on track with a scheduled commercial operations date in Q3. We will be ready from the upstream side with wells ready to turn in line immediately following the pipeline coming into surface, which gets us closer to achieving our first earn-out payment. All of this activity is exciting as is the potential to unlock value from this asset.

In the meantime, and in parallel, we will continue to push forward with drilling and completions within our Texas assets, where we continue to drive efficiencies and where infrastructure is in a more mature stage of development. Texas will comprise the bulk of our volume growth in 2026 and New Mexico should contribute more growth thereafter.

Briefly on our ERCOT power project within our RPC joint venture, our first site, a 10-megawatt facility located in Ward County, Texas, is in the final commissioning stage with ERCOT. During the commissioning stage, we've been generating power into the real-time market and collecting a modest amount of revenue. We have a forecasted commercial operational date for later this month, after which we can begin regularly participating in the day-ahead markets.

Our second site is fully constructed and is in the early commissioning stage. Our final 2 sites are scheduled for late summer. Over at our behind-the-meter project at Champions, we're saving approximately $200,000 per month or more on avoided negative gas sales at recent prices. Between these 2 power projects, our thesis remains intact here, and we see this as one small way to counter the weak regional gas pricing that we're realizing on our upstream assets.

As always in our capital allocation process, we plan for optionality. As the year progresses, we will monitor the macroeconomic backdrop and industry conditions, and we will maintain flexibility to speed up further or slow down should conditions deteriorate materially.

Keep in mind, the original accelerated plan was contemplated at a $60 price. These strong financial and operational results, along with the opportunities on the power side as well as additional new opportunities we continue to evaluate on a product of our exceptional operational, planning and technical teams. To our employees and our investors, we believe Riley Permian is well positioned for an exciting 2026 and beyond, supported by our high-quality asset base and strong financial position.

I'll now turn the call over to John Suter, our COO.

Thank you, Bobby, and good morning. I'll briefly cover our first quarter operational results and how activity progressed through the quarter, and then I'll touch on how we're positioned as we move through the balance of the year. Safety remains foundational at Riley Permian. To start the year, our operations reported a 0 total recordable incident rate, and we delivered 96% safe days.

Turning to operations. Development activity ramped meaningfully in the first quarter and was concentrated primarily in Texas. On a net basis, we drilled 15.6 wells, started completions on 12.8 wells and turned 8 wells to sales.

Importantly, we delivered this increased level of activity with strong capital discipline. Total capital spend was $47 million, which was below the guidance range, driven primarily by normal timing dynamics, including selective deferrals and infrastructure timing and a small amount of activity mix changes that reduced spend without impacting our plan.

From a production standpoint, net oil averaged 20.2 M barrels per day and total equivalent production averaged 35.6 MBOE per day, exceeding the high end of guidance. Volumes were essentially flat quarter-over-quarter as strong development well contributions offset normal base decline.

Winter Storm Fern caused disruptions across the Permian among midstream providers and producers alike in late January and into early February. We, on the other hand, experienced minimal downtime with little to no impact on quarterly volumes.

Within the quarter, development well performance was particularly strong. Initial oil volumes exceeded forecasts, and the outperformance was driven more by well productivity than simply timing.

As we look ahead, we'll continue executing the plan with a focus on safe, reliable operations and disciplined capital allocation. In the second quarter, activity is expected to increase from the first quarter with 2 rigs running full time and 16 to 18 planned completions by quarter end, 30% more than in Q1. This level of completion activity will contribute to a production ramp that we will see later in Q2 and drive strong full year growth.

Completions are expected to remain focused in Texas, while we work through gas takeaway sequencing in New Mexico, including the progress of the Targa gas pipeline project, which Bobby alluded to earlier.

Looking into the back half of the year, our current plan contemplates releasing the New Mexico rig in the third quarter and continuing to drill in Texas with a return to New Mexico activity later in the year to align our completion cadence with infrastructure readiness and set up the broader New Mexico program.

Now let's move on to operational performance in Q1. Lateral drilling performance continued its multiyear upward trajectory. A higher median lateral feet per day in combination with a tighter distribution demonstrates repeatable, scalable execution. Consistent use of multi-well pads and zipper fracs materially reduced downtime and per well cost while improving overall operational consistency.

We drilled a record spud to TD well for a 1.5-mile Yoakum County San Andres well in Champions at 4.28 days and a separate spud to rig release record at 5.79 days. We also successfully executed drilling and completing 2 more 2-mile laterals, delivering the fastest drilled wells in the field at 1,456 lateral feet per day, validating the efficacy of longer reach designs.

Well costs as it relates to drilling and completions year-to-date have been relatively stable despite inflationary pressure on service prices, primarily driven by efficiency in our operations. Diesel costs have obviously come up substantially in the last couple of months, driving many service companies to adjust pricing accordingly.

Our ability to drill faster and complete more efficiently has allowed us to mostly outpace this increase thus far. LOE has gone up slightly quarter-over-quarter in Q1 when compared to Q4 2025, in part due to some elective workovers that were deferred from Q4.

Bigger picture, it should also be noted that despite being up quarter-over-quarter on an LOE per BOE basis, we're still seeing a downward trend year-over-year with a 10% reduction in cost when compared with Q1 of 2025. The elective work I previously mentioned was primarily in our Red Lake asset, where many of our older wells have found new life following mechanical interventions. These workovers have resulted in nearly 500 net barrels oil per day of relatively flat production with some recent wells continuing to increase in oil cut.

This is some of the most capitally efficient dollars we spend with economic metrics comparable to new drilled wells in the area. We estimate that to date, we've only realized 30% of the possible uplift of these older wells and between the sizable inventory in our New Mexico asset and the combination of higher commodity pricing, the magnitude of unrealized production growth could be even greater.

We've also mentioned in past calls, our expectation of chemical costs coming down in New Mexico as part of a change in program we implemented in January. I'm happy to report that in just a few months, we've seen costs nearly cut in half on a per barrel basis compared to our 2025 monthly average spend. While we're starting to see that creep back up due to an increase in petrochemicals costs across the board, we're confident that the changes we've made will help minimize the effect going forward.

Stepping back, the message is straightforward with several key takeaways. We're executing safely and efficiently while scaling activity with discipline. We delivered strong first quarter volumes and capital performance. We're seeing continued gains in drilling and completion execution that help offset service cost inflation.

And finally, we're prioritizing Texas where infrastructure is ready, while sequencing New Mexico activity around the Targa takeaway build-out to protect returns and preserve flexibility as we move through 2026.

I'll now turn the call to Philip.

Thank you, John. I'll cover first quarter financial results and provide an updated company outlook. Unhedged revenue increased by $17 million, or 17% quarter-over-quarter, driven by 18% higher oil revenue and partially offset by weaker natural gas and NGL revenues. Gas and NGL revenues after fees were negative $11 million and reduced our total net revenue by 9%. Structural gas egress constraints, combined with seasonal midstream maintenance programs negatively affected gas pricing for producers across the Permian.

Our revenue net of derivative settlements declined by $3 million, or 3% to $102 million, driven by gas and NGLs, as hedged oil revenue was flat. Operating cash flow was $47 million or $55 million before changes in working capital.

Analyzing quarter-over-quarter variances, this cycle may be less relevant given some unusual impacts in the fourth quarter 2025 related to the midstream gain and corresponding income tax impacts. Adjusted EBITDAX declined by $5 million, or 8% quarter-over-quarter to $61 million, driven by $3 million of lower gas and NGL hedge revenue, combined with $2 million of higher operating costs and production taxes.

We're reporting a net loss on a GAAP basis of $70 million, driven by $127 million loss on derivatives, 91% of which was unrealized. We entered the year materially hedged to protect the 2026 capital program. The bottom line net impact should reverse over time as the mark-to-market loss is offset by increased revenues from corresponding production over the same contract periods.

GAAP mark-to-market accounting can introduce significant period-to-period volatility that does not reflect underlying operating results or long-term cash-generating capacity. Most energy investors are familiar with these limitations and will evaluate performance accordingly. Our business continues to generate meaningful cash flow, which should increase materially in the coming quarters if oil prices remain elevated, as we're only about 67% hedged for the balance of the year.

Here's one anecdote on the hedging to consider. We underwrote the acquisition of Silverback a year ago, when spot oil price was in the $60 range and the 12-month forward price was in the high 50s. We financed the acquisition using 100% debt with 0 dilutive equity.

Many of the hedges we have today are a result of that financing. Since then, in this new price environment, and assuming closer to a $70 long-term price, the value of that asset and undeveloped locations have increased materially, which is not reflected in our reported financials.

For example, consider the value of an undeveloped location. Incorporating an oil price of $70 versus $60 increases the net present value at a 20% discount rate by 60% to over 100%, depending on the type of well.

Moving on to our investments. First quarter 2026 total accrual-based CapEx was $47 million, while cash CapEx was $31 million, only 2/3 of the accrual amount, which is not unusual in a cycle when you're increasing activity rapidly given the time lag of payables.

We had several smaller acquisitions and divestiture deals for a net benefit of $5 million based on selling some small nonoperated assets. With remaining cash, we invested $4 million in the Power JV, or $2.5 million net of a small distribution, paid $8.4 million of dividends, reduced debt by $8 million and bought back $4 million of stock.

Now let's discuss our outlook. We have a big second quarter of development activity, and we're guiding to $80 million of accrual CapEx. For the full year, we're increasing our full year guidance range by $10 million, representing a 5% increase at the midpoint of $210 million, driven by a mix of operated and nonoperated incremental activity and partially offset by some savings achieved. With our own operations, we're likely to have about 5 more wells drilled and 1 to 2 more completed as compared to the March outlook.

We're also seeing a modest pick up in nonoperated proposals from adjacent producers. Incorporating these updates and based on confidence with the assets and optionality inherent with the development program, we're raising full year production volume guidance ranges by 5% to 22,500 barrels per day at the midpoint, corresponding with the 30% year-over-year growth that Bobby mentioned at the start. We see that growth beginning modestly in the second quarter, followed by the largest gain in the third quarter and another gain in the fourth quarter.

Accrual CapEx looks to be weighted 60-40 between the first half and the second half of the year, while production volumes will have a lag effect given the nature of development and turning wells to sales, with oil forecasted volumes weighted at 45-55 for the first half, second half. This combination may lead to less free cash flow in the second quarter with stronger free cash flow in the fourth quarter. So this is dependent on execution, timing dynamics and market pricing.

For the full year, we forecast a reasonable CapEx reinvestment rate of approximately 65% to 70% of operating cash flow before working capital and midpoint guidance and based on current forward oil prices. We anticipate the majority of excess free cash flow after the dividend will be allocated to debt paydown to further solidify our balance sheet and to provide future optionality with a smaller amount possibly allocated to stock buybacks depending on market conditions.

Our measure of capital efficiency may differ from some larger companies looking to prioritize and maximize free cash flow, which implicitly calls for restrained investment. We're excited to invest meaningfully this year in our high-returning assets, which we believe will yield this differentiated growth profile that we've described today.

Thank you all for your attention and interest in our company. Operator, you may now turn it over to questions.

[Operator Instructions] Our first question comes from the line of Derrick Whitfield from Texas Capital.

Congrats on a strong 1Q and 2026 update broadly. First, I wanted to focus on your activity plans as we're clearly in a very fluid situation in the Middle East. With today's revised activity plan and workovers and recognizing the strength of your -- and the growth of your program as it stands, how would you characterize your desire to further lean into this favorable environment from a workover perspective, nothing more?

And then as you look out to 2027, is this level of activity a good run rate for the efficiency of your operations?

Derrick, this is Bobby Riley. Let me start. Like I mentioned in our deal, when we looked at our activity level this year, we were faced with about a $60 current price and $60 outlook. And we thought at those numbers, we warranted developing at the pace that we are. I mean, like we talked about in the last couple of years, we've been in the acquisition mode to build inventory. And now we're sitting on a significant amount of long-term drilling inventory and the ability to capitalize on that value even at $60. So we would have to see a significant drop to adjust the direction we're going now. And with the efficiencies that we're seeing in drilling and completions, with sustained price in this level, we could actually add another 5 or 10 wells for the next 3 months.

So I mean, we're a growth company. And I think you're going to receive long-term share value, the bigger we get organically. It's our highest rate of return.

Yes, Derrick. And to follow up on one of your other questions, can this efficiently move into '27? I think this year, we're running 2 rigs really just to hold a few things in New Mexico with some permits we had expiring and some lease obligations. But really just the fact that with our fast cycle times when we can drill 50-plus wells a year with 1 rig, we can easily do that. And certainly, a frac crew can frac up to, I don't know, gosh, 90 to 100 wells per year. I mean it's that efficient.

So it doesn't take a lot of extra service company action for us to be able to stay at a pace that provides tremendous growth if we plan to just keep it going all year long. It's really not a matter of how much we add. It's just how much we use what we have for how long during the year. So I hope that helps.

It does. Makes sense. And then just based on your current 2026 upstream capital plan, how should we think about the potential earnout of contingent payments from your midstream sales agreement? And when could you start to recognize that benefit?

Yes, Derrick, this is Philip. I think we have line of sight on that for early next year. The wells that John and Bobby are talking about in New Mexico, we've got a slug of those that will come on. There's a threshold that we cover for a period of days and then there's a little timing. But we feel pretty confident about hitting the first earn-out, which is $30 million in the first half of '27, with subsequent ones probably a year after each.

Our next question comes from the line of Neal Dingmann from William Blair.

Sticking with the production question. My question is on your growth. I know, Bobby, for you or Philip, I know operationally and financially, you certainly have the ability to materially increase production if you choose. I'm just wondering how much is the decision and kind of the guide you talked about, how much is that influenced by -- you've had negative natural gas and NGL prices? And how much do other things like, I don't know, incremental takeaway or power fit into this growth decision?

Sure, Neal. I can start. Yes, look, the gas, it's frustrating, but we do see it getting better. I think what we and other producers experienced in the first quarter was a combination of the structural constraints I mentioned in prepared remarks and then some of that seasonality.

You look at the strip, and it is getting better each month. We've got about 5 Bcf a day coming on among those projects that are widely discussed, GCX, Blackcomb and Hugh Brinson towards the end of the year, that should help. And then at the same time, I think you typically find the correlation between gas price or the Waha price even and oil price with most of the growth in our domestic gas coming from associated Permian. And so as the oil price is moving down here, I think the Waha price will become less negative.

Like I said, it's frustrated not to be making more, but it still does -- margins and returns look very good at $70, $80 oil. So we'll continue with that. As far as there being a physical constraint, we've got the items we need lined up. John referenced some of that and power doesn't seem to be a problem right now. We've got both what we need, what we've built out solidly, but then you've also got the short-term type of generators and such that can even run on natural gas, which is quite economic these days.

Great. And then, Philip, just a second question on -- maybe for Bobby on M&A. Just wondering, much like organic growth, you certainly have the balance sheet now to support really an active M&A program if you choose. Just wondering are there active deals out there? How do they look in this environment? And maybe just with that same vein, what -- where does your current inventory depth sit?

Yes, I'll start on the M&A first. So typically, what we find in our industry is that M&A is tough in periods of high volatility. The high prices themselves are not a deterrent, but it's hard to underwrite when prices move around so much. When the prices were quite low, sellers were on the sidelines. I think we'll see a few more packages come to market at the high prices for people to so-called test the market. It can be tough to underwrite them, though, both with the volatility and even some steep backwardation.

So we want to be careful. You're right, we do have a stronger balance sheet, and we have flexibility to do that should something come together. But we want to be mindful of how we're both underwriting deals and where in cycles we're buying them. We felt great about buying Silverback last year at $60. As I mentioned before and we feel good about that.

We've done 3 deals in 3 years. We've got quite a bit of inventory. We've held back on the CapEx for a while as we digested those and got the infrastructure ready. And at this point, we're focused primarily on the organic development. And I think that's how you should think about it. It's primarily organic. If something should come together on M&A, we'll feel fortunate, but not holding our breath.

Our next question comes from the line of Jeff Robertson from Water Tower Research.

Bobby or John, can you talk about the guidance of the production uplift in the sense of how much of the increase is due to timing versus performance-related issues with the wells that you're bringing on?

Let me start, John, and then you can finish. Obviously, the acceleration is something to do about timing. We're -- we currently have 2 rigs running with a frac crew right behind one of them. So we're bringing things on a little bit quicker.

But also performance so far that what we're seeing this year, I think all the wells that we've completed this year exceed our predrill forecast, some of them significantly. So John, you might add to that. But I mean, I think it's a combination of working a little faster and the wells are meeting or exceeding our production expectations.

Yes, absolutely. And just to follow that up with a little bit more specifics, we've drilled a number of 2-mile laterals this quarter, which have just been fantastic. You hope you -- a lot of times, 2 miles will keep things flatter, but we've actually seen some uplift in pressure and rate from these. So we're excited about that.

Also, we've -- in Champions, the vast majority of our wells are child wells. And these wells, we've been finding out tend to cut oil faster and reach a higher oil peak sooner than our parent wells, which ends up delivering superior early time performance. So that's a lot of what we've seen this quarter to hopefully answer your question.

And then let me say one final thing, Jeff, on timing as far as how it all comes together for the company and in the quarters is we do have quite a bit of back-end weighted growth. So the first quarter, we've gone through that was roughly flat with the fourth quarter. We've got some modest growth here, 4% in the second quarter at the midpoint. And then it really starts to take off you can back into the math between what we've done so far and what we're guiding to full year.

But you can see that the back half of the year is basically between 24,000 and 25,000 barrels a day, which suggests pretty material growth from where we are now and what we're guiding to.

Well, if there's any risk with respect to the production outlook in the second half of '26, is there much risk or much cushion built in for timing issues around Targa completing the projects?

Yes. I think we're in a good shape. As Bobby said earlier, we'll be doing Texas primarily. We've got some optionality built into the plan. John was describing how he's going to have some DUCs ready. But we've got a plan basically to hit this, so we believe should the timing work out either way. John, do you want to add anything there?

Yes. No, I mean, I think our Champions development is going to carry the day all throughout the year. But we expect the permit for Targa for the high-pressure line to come any day, which then will be a several month period of construction.

And that's why we've said in Q3, it could happen slightly faster. But even if there's a delay in that, the high interest Champions wells where we already have infrastructure, that's going to solidify that second half, I think. But the New Mexico stuff will be kind of gravy on top of that.

John, with plans to drill 42 to 48 net wells this year. Can you talk about how your ground game is working to replace inventory?

Yes. Well, we are drilling some wells on the east side of Champions, and that is -- we're just now completing them. We've been buying some extra acreage out there, and we're really excited to see where that could lead us on the east side.

But in New Mexico, really, we have very few PUDs booked. So there's going to be -- as we drill some of these wells, we add PUD reserves. And certainly, as we test various edges of the fairway, that's going to lead us to have the potential for additional leasing.

What I love about New Mexico is that it's a forced pooling state, and we probably have 500 gross sticks, maybe a few hundred net. But with an active rig in that field, you can pick up -- oftentimes pick up a lot of interest from other people. That all just depends as we know, but we're excited to be an aggressive player out there in the Northwest Shelf and to hopefully be rewarded with picking up interest.

Lastly, LOE per BOE was $7.51 in the quarter, which was well below your $8 to $9 per BOE guidance. Can you talk about the drivers for that first quarter performance?

Yes. As I mentioned in my remarks, we've just in the first quarter, capitalized on some rebidding and some realignment of vendors. And in New Mexico, I think we've cut our per barrel chemical cost in half with this new change. Also straightened out some things in Texas.

This chemical program has also helped us from -- it's actually working. That's less tubing strings you have to replace less ESPs to replace when you have to replace the tubing. So that really starts having a cumulative effect.

And on the other side, the productivity of these wells has also helped us with, I'd say, some volume expansion has helped us on the divisor side of that per BOE metrics. But look, we're proud of what we're accomplishing. I think we're one of the best operators on the Northwest Shelf, put our team up against anybody as far as being able to get the most out of the wells that we purchase and the acres that we exploit. So no, we hope to make continued improvement.

[Operator Instructions] Our next question comes from the line of Nicholas Pope from ROTH Capital.

Curious as you kind of look at the differences between Champions and the Red Lake area with one rig kind of running in each. What's the difference, I guess, in kind of total drilling complete costs between the 2 assets? I think it's -- there's a lot of mix going on between these 2, and it seems like it's shifting a little bit throughout the year. So I just want to make sure I kind of pinpoint kind of the spend differences between the 2 assets.

Yes. Typically, we drill 1.5 miles wells in Champions just because that's the -- that's how it was set up. And in New Mexico, we're pretty well generally limited to 1-mile laterals. Again, it's not impossible that if things line up right that we can drill more.

Remember that New Mexico is at about 3,500 feet TVD. So 2-mile wells are possible, but you really can't do a whole lot of kickout and then drill 2 miles when you've got that little bit that small of a vertical segment.

So cost-wise, it ends up being about, I'd say, $1 million more in New Mexico per lateral than it does in Texas. And I'll say that's at the moment, we are doing a ton of testing. We've done spacing tests. We're doing frac tests.

The thing that makes New Mexico a bit more expensive is that in Texas, we do cross-link fracs there in San Andres. And in New Mexico, in the Paddock and Blinebry, we primarily do cross -- slick water fracs. The slickwater fracs take a lot more fluid, more pump time. And so we are looking and have already performed cross-link frac on a recent test are really encouraged about that.

So there's more to come on that in the future. I mean, that in itself could be $0.5 million plus savings per well. But again, we also want to see what is the most oil recovered and be efficient in recovering our resources, too.

So a lot of testing going on there in New Mexico, and I feel comfortable that our costs will be coming down over time. But that's kind of the primary difference between the 2 assets at the moment, cost-wise.

Let me add one thing to that. In Texas Champions, we own roughly closer to 100% of each one of those wells that we drill in New Mexico, it's significantly less. So we have to drill a lot more wells to get the same net impact to make sure everybody understands that it's not one for one.

We could have 50% to 60% working interest in New Mexico where we have 100% in Texas. So don't be alarmed by the well count because on a net basis, it seems more reasonable.

Got it. And then kind of digging a little bit deeper into kind of the rig cadence that you all are talking about with the Targa plant kind of scheduled start-up, it sounds like -- I'm just curious what stage you're getting the New Mexico wells to? Is it just purely drilling state in the completion for once the Targa plant comes online?

And I guess, how many, I guess, wells are you all anticipating kind of having ready to go upon start-up of that Targa plant? It sounds like things are going to be held back until kind of you can let the field breathe a little bit.

Yes. So in New Mexico, we started up a rig at the end of the first quarter, I believe. And you're correct. We are drilling and getting these wells ready for completion, but just in sake of capital efficiency, there's no use completing them and letting them sit there until late Q3.

And so we'll take a look at that as far as whether we start a little bit early fracking these wells, kind of depends on what the oil price is at the time and a number of other things. But we should have 20-plus wells. Again, these drill so fast that you're drilling a well a week and skidding over and knocking a whole pad out that way.

So it should be 20-plus wells plus a substantial amount of volume that we have from existing PDP that's already there flowing to another processor. So when we get all of those wells that we're drilling in '26 now ready to go, we'll be a long way towards getting that volume to meet that first earnout.

We do have to produce it steadily like that for over a quarter or for a quarter to get that earnout. So like Philip said, maybe the end of the first half of 2027.

And our last question comes from the line of Noel Parks from Tuohy Brothers.

I did hear you mention earlier that you had seen some modest pick up in non-op participation, I think, from adjacent partners. So I was just interested in that I had heard something I think from another operator and just thinking maybe the decision-making is a little different compared to -- in the current price environment compared to how public operators are approaching the environment.

Yes, I'll start. Yes, I think you said the right word, public. So this is in New Mexico where I'm referencing that, and it's dynamic, John mentioned, which is forced pooling. You've got generally just more chopped up ownership, overlapping ownership, and it's not uncommon to participate in each other's wells out here. We got the majors, the largest oil companies in the world participating in our wells, to be honest.

So yes, we've got a couple of proposals from some private operators, whether that's a coincidence or not relating to their desire to increase activity. It may just be this was somewhat on the plan. We weren't sure exactly when it come, but now they're here.

So yes, we've got a few proposals. Those are coming now. We're happy to do it. These are great returns. No reason not to participate in those.

Okay. Great. And actually, I guess it goes for both New Mexico, we're talking about, but also interesting thinking about Champion. How many operators are also actively drilling in your vicinity for each area?

Yes, I'll take that. I would say in New Mexico, it would probably be 2 with -- one of them more sustained and the other one just every now and then. And then in Champions, we are by far the leading driller there. I think there is another company that might drill, I don't know, 4 or 5 wells a year. Yes, 2 at most, but they really don't compete with us in the direct area.

Okay. And not so much thinking about large-scale M&A, but just from an A&D perspective, is there -- I mean, I guess if you're -- if the burden of the land work and so forth is going on, is there considerable extra inventory just from -- I don't know if it's say abandoned properties, but just since especially Champions is such an old field, is there much else to do if the ownership could be, I guess, concentrated, bought out, out there?

I'll attempt to answer that. Champions, I'd say, it's mostly blocked up and spoken for. Look, all of this, I think, whether where we are in Texas or New Mexico or most likely throughout the Midland and Delaware, you have a few areas where there's just available unleased land, right?

People have discovered where the resource is and have gone to try to capture that. There's always some work to be done to get that, and we give our thanks to our land teams to get that done. I think that's some of just the magic that happens with producers is getting that ready for drill and development. But it's a function of kind of piecing those together and getting them ready, finding whether it's old records or title or what have you. But it's not so much that it's just available and somebody hadn't thought to get it yet.

Yes. And I'll add on to that. But one thing to bring up in Champions that yes, we do control that, and we'll be drilling most all of that. As Bobby always mentions, there's a lot of upside left in Champions even once that thing is fully developed.

I mean, we only recover 8% of the oil typically on primary. But it's a field where I think you'll find a lot more oil to recover once we deplete the pressure down a little bit where other techniques will benefit getting more oil out.

And then certainly, in New Mexico, Bobby said we may have 60%, 70% of a lot of that acreage. There's always people willing to sell in the right situation or to trade. So there is upside there, too, from either acquisition or just some good land work.

Also, we look at adding inventory when we're analyzing different benches and it's not so much in Texas, but in New Mexico. There is some work being done in one of the upper benches that could significantly add inventory.

Great. And just to clarify, is that -- when you talk about alternate benches, are those things that have sort of similar deposition to the benches you're producing? Or are they more intermittent up there?

It's pretty much the same. It's just adding another zone that's been tested and produced vertically, adding it into the mix. So we're looking real hard at the number of wells per section that we'll be drilling in Texas, including based on our spacing test. We could be adding an additional Blinebry or maybe an additional Paddock and then additional uphole zone.

So we're still actively -- I would not be concerned about the ground game. There's plenty of opportunity for us to add stick in addition to the numerous other organic projects that we have in-house.

Thank you, everyone. That concludes our conference call for today. You may now disconnect.

Hello, and thank you for standing by. My name is Regina, and I will be your conference operator today. At this time, I would like to welcome everyone to the Riley Exploration Permian, Inc. Fourth Quarter and Full Year 2025 Earnings Release and Conference Call. [Operator Instructions]

I would now like to turn the conference over to Philip Riley, Chief Financial Officer. Please go ahead.

Good morning. Welcome to our conference call covering our fourth quarter 2025 and full year 2025 results. I'm Philip Riley, CFO. Joining me today are Bobby Riley, Chairman and CEO; and John Suter, COO.

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 contains 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. We'll also reference certain non-GAAP measures. The reconciliations to the appropriate GAAP measures can be found in our supplemental disclosure on our website.

I'll now turn the call over to Bobby.

Thank you, Philip. 2025 was a transformation year for Riley Permian and we look forward to discussing our fourth quarter results and our 2026 plan this morning. Over the course of the year, we made significant progress across several strategic initiatives, positioning us for long-term value creation.

Through our Silverback acquisition, which closed in July, we enhanced depth and duration of our undeveloped inventory in our portfolio. Combined with our previous acquisitions in New Mexico and our legacy Champions position, we have 7 to 8 years of high cash on cash return undeveloped inventory.

In December, we sold our interest in our New Mexico Midstream project to Targa, a best-in-class Fortune 500 midstream infrastructure company with a premier integrated asset network for $123 million in cash, plus $60 million in future potential earnouts. The project will provide flow assurance for our New Mexico gas production and enable us more robust development of our New Mexico assets as originally intended. This transaction eliminates all liabilities and future construction costs associated with the project, allowing us to focus more capital into the drill bit and less into infrastructure. The project is underway and Targa expects the project to be operational in the second half of 2026.

We reduced our debt by $120 million during the fourth quarter, reinforcing our financial flexibility and positioning the company to accelerate development in 2026. The disciplined groundwork late in 2025, portfolio expansion, infrastructure build-out and balance sheet improvement sets the stage for more active and value-enhancing development program in 2026 and the years ahead. We authorized a stock repurchase program of up to $100 million of currently outstanding shares of the company's common stock and began repurchasing outstanding shares in January of this year. We repurchased approximately 152,000 shares at a weighted average price of $26.54.

The decision for accelerated growth is not in response to the recent increase in oil price levels, but rather the result of Riley Permian's multiyear positioning and our long-term view on value creation. For 2026, we forecast over 20% year-over-year oil volume growth. While we are excited about this growth potential, we will remain flexible and ready to moderate activity and spend appropriately should oil price environment deteriorate.

I would like to thank our entire team for the success and transformation we realized in 2025. We're positioned for an exciting 2026 and beyond thanks to our strong financial position and asset base.

With that, I'll turn the call over to John Suter, our COO, for operational highlights, followed by Philip Reilly, our CFO, and who will review financial performance.

Thank you, Bobby, and good morning. I'll briefly cover fourth quarter and full year results followed by 2026 development plans. Beginning with the fourth quarter, our development activity was focused in Texas. Activity levels match the ranges we provided in guidance with more drilling and completions than new wells turned to sales. wells drilled, but not turned to sales during the fourth quarter should come online over the first and second quarters of 2026.

Oil production increased by more than 1,700 barrels of oil per day or 9% quarter-over-quarter. This was primarily from improving volumes from the new wells brought online earlier in 2025 that continued to increase as well as from the 3 new wells turned to sales during the fourth quarter. Comparing the fourth quarter of 2025 to 2024 and oil production increased by 26%. As for the full year 2025, I'd like to begin by highlighting another year of excellence in safety here at Riley Permian.

We achieved a total recordable incident rate of 0 in 2025. We also achieved 95% safe days, a metric requiring no recordable incidents vehicle accidents or spills over 10 barrels. Full year oil production increased by 15% year-over-year while total equivalent production increased by 29%. The overwhelming majority of our full year production increase was from pre 2025 development with modest contributions from 2025 new wells and smaller contributions from the Silverback acquisition for the second half of the year, including the benefits of workover volumes as discussed last quarter.

Full year development activity counts were relatively modest compared to 2024 levels as we reduced activity midyear last year, following the oil price decline and our Silverback acquisition. In total, we drilled 18 net wells in 2025 or 28% fewer than in 2024 and turned to sales 16.3 net wells or 23% fewer than in 2024. I highlight these metrics for a couple of reasons.

First, we achieved impressive organic volume growth with relatively limited activity. This is a testament to our high-quality drilling portfolio. Volumes from the acquisition accounted for only 8% of total annual volumes. Second, this reinforces what Bobby discussed on framing our 2026 plans for significant increased activity relative to the lower activity in 2025 and readiness positioning with midstream and water takeaway projects. In Texas, we essentially held over 11,000 barrels of oil per day of oil production flat year-over-year with only 10 net wells turned to sales again, demonstrating the productivity and efficiency of our wells.

In New Mexico, production has been more consistent and reliable. Since commissioning the expansion of the compressor station in December, we've been able to send more gas to the high-pressure system, increasing uptime and unburdening the low-pressure system by which the remainder of our gas is gathered. Overall, New Mexico oil production grew by 74% and or over 2,500 barrels of oil per day year-over-year, benefiting from just 6.3 net wells turned to sales and from the Silverback volumes.

New Mexico represents a growing share of our total company oil production from 23% of the total in 2024 to 34% in 2025. That trend will continue into 2026 and beyond. The Silverback acquisition continues to surpass by case expectations, producing at a 65% higher oil rate at year-end than anticipated. This is primarily due to strategic workovers, including wellbore cleanouts, artificial lift optimization and return to production operations. As for drilling and completion operations, we're down 25% in cost per lateral foot in Red Lake year-over-year.

Similar results were achieved in Texas with a 15% cost reduction per lateral foot in 2025. Both achievements were driven primarily by a focus on pad drilling and increase in time spent drilling and completion and optimization. It should be noted that while completion optimization helped on the cost reduction side, we're also seeing it result in an increase in productivity in both our Texas and New Mexico wells with both sets of wells generally beating internal forecasts. We're also optimistic about future optimization that could further drive costs down. including increasing completed lateral length and testing new completion methodology in New Mexico.

Let's now discuss our plans for 2026. Our current plans call for significant increases in activity and volume with activity and spending being more concentrated during the first half of the year, while volumes may grow each successive quarter. On a full year basis, we're essentially running slightly more than an equivalent continuous 1-rig program. In actuality, we have 2 rigs running for approximately 3 months through May, back down to 1 rig for the summer, down to 0 potentially for the fall before picking 1 up again later in the year. We picked up the second drilling rig last month that began drilling in New Mexico to complement the rig already running in Texas that was put in service October of last year.

This 2-rig program allows us the ability to continue to grow our Texas production base while also setting the stage for more New Mexico asset development when the long-haul high-pressure line to Targa is completed in Q3. We'll begin to build volumes, striving to meet our volume commitment payouts as per the terms of the sale of the midstream asset in Q4 2025. Both rigs have relatively short contract terms, allowing us to be flexible in the event market conditions change rapidly. We currently forecast drilling 46 to 53 gross wells, which may correspond to approximately 37% to 43% on a net basis. Net completions and wells turned to sales may be slightly higher as we have a small inventory of DUCs to draw from as I referenced during my commentary on fourth quarter activity.

New wells turned to sales will focus in Texas during the first half of the year and transition to New Mexico for the second half. This is predicated on the Mexico gas infrastructure being completed and ready by that time, as Bobby described. Additionally, we've been working with partners to secure sufficient water disposal for this development plan. This will increase operating expenses, which we see impacted later in the year while we're also tackling initiatives elsewhere to offset this increase.

Philip, I'll now turn the call back to you.

Thank you, John. I'll also cover both fourth quarter and full year 2025 results with a few additional notes on 2026 guidance. The company's financial results for the fourth quarter were favorable to all guidance levels. Fourth quarter prices after hedges were lower quarter-over-quarter across all 3 commodities, though total hedge revenue decreased by only $3.8 million or 3% quarter-over-quarter, benefiting from $8 million of positive hedge settlements.

We experienced negative natural gas and NGL revenues after basis and fees. Like many other Permian operators who have reported this earnings cycle, pipeline maintenance constrained Permian gas egress and pressured Waha pricing during the quarter. We're monitoring the regional infrastructure build-out, which is forecast to improve by next year, absent delays. We have a material amount of Waha basis hedged next year at minus $1 to Henry Hub, which combined with higher index pricing and higher forecasted volumes, has the potential to translate to material positive revenue starting in 2027.

Core cash operating costs being LOE, production taxes and G&A before stock compensation, decreased in total by 13% quarter-over-quarter. LOE also decreased by 13% quarter-over-quarter or by 21% on a dollar per BOE basis with cost savings across many categories. Workover expenses were the largest contributor coming off the third quarter with higher workover activity immediately following the Silverback closing. We hope to continue realizing some aspects of the cost savings, while other aspects were unique to the quarter and may not recur going forward.

G&A before stock compensation decreased by 20% and G&A inclusive of stock compensation decreased by 18%, partly on account of coming off of an unusually high third quarter. A few items caused third quarter G&A to be materially higher, including the impact of a transition services agreement with Silverback immediately following the close, which was completed by the fourth quarter.

Net income increased by $69 million quarter-over-quarter, benefiting from nonrecurring items such as the $72 million gain from the midstream sale and from $20 million of higher hedging gains, which were mostly noncash and partially offset by $16 million of higher income tax expense due to the midstream sale gain. Adjusted EBITDAX increased 3% quarter-over-quarter to $66 million as $5.8 million of lower costs more than offset lower hedge revenue, increasing margin from 59% to 63%.

Cash flow from operations increased 2% quarter-over-quarter. Accrual capital expenditures for the quarter were $50 million, compared to $18 million in the third quarter. The CapEx increase represented a return to more normalized upstream activity compared to an exceptionally low level in the third quarter and an increase in midstream capital spend which is ultimately reimbursed with midstream sale. In aggregate, capital expenditures were at the low end of our fourth quarter guidance range, primarily due to a few new drills and smaller infrastructure projects that were deferred to 2026.

We converted 27% of operating cash flow to $17 million of upstream free cash flow and $1 million of total free cash flow. Note, the proceeds of the midstream sale did not flow through total free cash flow, while the CapEx does reduce free cash flow. I'll point out again that the midstream CapEx was reimbursed as part of the sale so the free cash flow metric has a bit lower utility this quarter. Debt decreased by $120 million quarter-over-quarter due to proceeds from the midstream sale resulting in a fourth quarter 2025 balance of $255 million.

As of 12/31, our credit facility was 28% utilized based on a $400 million borrowing base. Trailing debt to EBITDAX leverage was 1.0x on an as-reported EBITDAX basis or 0.9x on a pro forma basis, including first half 2025 Silverback EBITDAX. On a full year basis, to EBITDAX and free cash flow decreased by only 8% year-over-year despite 15% lower oil prices. Total free cash flow was 31% lower year-over-year driven by lower prices and higher midstream spend, which, of course, is nonrecurring.

We allocated 41% of total free cash flow to dividends, up from 26% in 2024 as dividends increased and free cash flow declined. We had a very active year of acquisitions and divestitures, as you can see on our cash flow statement. Silverback is represented as the $118 million business combination. The $2.2 million of acquisitions of oil and gas properties represents a small acquisition of minerals underneath our New Mexico properties that we completed earlier in the year.

We also had a good amount of success in 2025 with our land ground game reflected in a $1.3 million acquisition and effectively $3 million of new leasehold embedded in CapEx, which is labeled as the additions to oil and natural gas properties on the cash flow statement. In total, we estimate that we replaced about 2/3 of our completed locations from 2025 via new land, corresponding to a very attractive cost of entry of less than $300,000 per net undeveloped location.

Moving on to 2026. We currently forecast a capital plan of $200 million, corresponding to the activity that Bobby and John described. As of today, we forecast more than 2/3 of the capital spent in the first half of the year, at least on an accrual basis with a particularly large second quarter, then falling in each of the third and fourth quarters while oil volumes may rise through the year given the lag effect of investments converting to production. We see this investment benefiting not only this year, but providing a tailwind to 2027 as well.

In our investor presentation, we provide a 2-year outlook, illustrating 2026 and 2027 spending and production levels. Overall, we forecast a materially higher allocation rate of cash flow to CapEx this year. Of course, we'll monitor markets and aim to stay flexible throughout the year and will protect the dividend in lower price environments. We entered 2026 well hedged, partially on account of the midstream capital commitment we're occurring until mid-December and partially on account of universal calls for an oil surplus and weak pricing. And we've done some hedging over the past week.

As of March 2, we had approximately 70% of forecasted oil volumes at midpoint guidance hedged at a weighted average downside price of approximately $60 per barrel with 36% of those hedges structured as collars, preserving upside participation. Thank you all for your support and attention.

Operator, you may now turn it over for questions.

[Operator Instructions] Our first question will come from the line of Derrick Whitfield with Texas Capital.

Congrats on a strong year-end and also thanks for providing a multi-period outlook as well. Regarding 2026 and 2027, while I understand there could be off brands at a lower price environment. Could you help us shape production cadence for the year under the status quo plan as the implied average oil production for Q2 through Q4 is about 10% above the Street at present.

And then additionally, as we kind of think about capital efficiency over this period of investment throughout 20 would you expect it to improve in 227 as you optimize D&C designs get for Repsineti? And as you back out some of the DUC impacts 2026.

Yes, sure, Derrick. This is Philip. So you're going to see the production increase each quarter this year. And I guess to clarify, you're going to see a dip in quarter 1 is what we're forecasting. John could follow here with a little more color. But we experienced some downtime and some deferred production this quarter. We had some shut-ins from our legacy midstream partner, which caused a little bit of a dip there in the first quarter, but then we hope to achieve a nice ramp in the second quarter and third quarter and fourth quarter. I hope that answered the first question. I'll go to the second and then pass to John.

On '27, yes, depending on how you define capital efficiency, we've got a few different metrics. But yes, you could find that next year is more efficient and that's just the function of the delayed aspect of the investment converting to the production dim. So we hope to achieve another increase next year. It may not be the 25% increase like we hope to get this year, but maybe it's 10% or so based on, frankly, kind of flattish CapEx is what we're showing for now.

2027 is a long way, of course, but we did put that in there. I'm glad you appreciate it because it does show that kind of lag effect benefit there. John, do you want to say anything else on kind of the Red Lake shut-in?

Yes, sure. Yes, like Philip said, we did have some downtime in the -- due to some of the heavy weather freezing temperatures and then like you said, some issues with our pipeline. But all the more reason why we're really looking forward to Q3 when we'll have our new pipeline in place. We're excited about that. Like we -- several of us mentioned that there'll be heavy champions activity in the first half of the year. And then we're we kind of reduced in the third quarter and then in the fourth quarter, we're shifting to New Mexico again, we need that trunk line in place from Targa, and that's on schedule to happen. And so really excited about that.

We'll start ramping up our completions still won't get the full impact of it in Q4 because a lot of things are being completed then and we'll have to dewater a little bit, but all the better for '27 as we should be able to start drilling more efficiently in Denver in New Mexico and completing those wells as we go. So should be more efficient without having to wait on some water infrastructure and some gas takeaway like we are this year.

Great. And John, maybe staying with you, in your prepared remarks, you mentioned completion optimization. Could you elaborate on some of the notes that you're turning for completion optimization or D&C optimization? And what you're seeing in well performance versus past designs.

Sure. Well, we -- again, we've been mostly in champions. We're trying to do zipper fracs on pad drilling, zipper fracs on everything we do. We kind of think we found the optimal recipe there. We've reduced from say, 700 to 800 pounds per foot down to 250 to 300 pounds per foot of sand. And so that's a big change over time. goes against what we hear in the shale world. So we're getting a big cost savings from that. We also have found that 2040 works better than 40 70, which is often more readily used.

But we've also -- the other thing is we've reduced our clusters, but still are using the same amount of sand, but we've -- it reduces our water volume and of course, less pump time, which is a cost benefit. In Mexico, there is upside there that we have tested a little bit. We plan to test more in 2026. The hepatic layer of the blindary is very similar to the San Andres over in Texas. And we would like to test more cross-link fracs there.

We've done it once in 2025, I believe, and we've seen good outcome, but we have a lot more testing to do, but it could provide a significant financial benefit somewhere between $0.5 million plus per well. So we're excited to do some more testing there. Again, once we have that pipeline, we'll have the freedom to do a little bit larger scale drilling.

Maybe, John, just to clarify on the optimization. It sounds like it's more cost and you're getting similar performance. Is that the right way to characterize it.

I would say in champions, that's probably true, albeit our wells are outperforming our general type curves right now. Some of that is due to, again, more child wells are being drilled in champions because again, we're later in the development stage there. those wells tend to reach peak oil faster. So that's another reason that's causing that in Champions.

Our next question will come from the line of Neal Dingmann with William Blair.

Great update. Phil, maybe a question for you or Bob or John. Just again sticking with that Slide 10. I've always loved the flexibility. Again, it certainly seems like in past years, it hasn't been 1 rig that you've needed to have very material production growth that I'm just wondering, given now today in shoot, we're almost now back to $80 oil. How flexible is this plan? And I know a lot of larger companies, I would say, hey, we're just going to target flat and target free cash flow growth.

But again, given your returns that you show on other slides, would you think about trying to capture this oil upside and even potentially grow quicker than just maybe talk about the flexibility of the plan, I guess, is the best way to ask it.

Yes. I might diverse some of that to Bobby for a longer-term view of that of increasing. But certainly, we're talking about drilling, what 45 to low 50s gross wells. The beauty of of our wells being so shallow that compared to the Delaware is that we can knock well out from spud to TD, maybe 4 or 5 days, certainly a week by the time you get everything wrapped up and then doing pad drilling, it's really quick sliding to the next one.

So 1 rig can effectively drill let's just say, upper 40s to low 50s wells per year if you're able to not do a lot of regional moving. So it would not take much in deployment to be able to really drill quite a few wells. So we have the capability. I may star that back to Bobby to see what he thinks about drilling at a higher oil price.

Thank you, Neal, for the comments you made. I'm going to say we're probably not in a position today to be reactive to a $5 increase or $4 increase in the price of oil. I think we have a solid plan laid out for 2026 with a pretty significant D&C capital spend that really we're looking into '27 and beyond and how that going to affect this company in any price environment, whether it be $55 or $85. We have the ability with the flexibility like John mentioned, we could either shut these rigs down if we needed to or keep the rig running for the entire year. We have that option ahead of us. It's just too early to immature to really say what we would do at this point.

Yes, that makes sense, Bobby, and love the flexibility. Second question, Phil, you know I can't help but ask on the powers. Obviously, there's positive on that. I know I was looking at Slide 16, you guys talked about, I think, now even on the second project, it's in the final stage. Could you talk maybe just update on that, where that second project sits? And have you considered even adding more power beyond project #2 because, again, obviously, I'm a fan of this. And again, I think as the market would love just to hear any more plans to be on Project 2.

Sure. Thanks. Yes. So the second project is this merchant project we have in ERCOT in which we take our lower-cost gas and convert that to electrons to sell to the ERCOT grid that project itself has 4 sites, and the first of the 4 sites is in the final stages of commissioning. With ERCOT that has a kind of 4-week process where you're testing with ERCOT demonstrating your ability and competency to reliably deliver that power we're getting ready for that. And then we should be in a position to enter effectively the day-ahead trading, which is the kind of power that we plan to provide and offer for the grid. It's not a long-term thing, but it's something that we then think is flexible.

You can react. We -- our partner has a very active trading desk there that you can look at the dynamics, both gas and power and make decisions on that kind of basis. Ultimately, this is for it's for a few things, but one of the primary things is, frankly, to try to improve effective netbacks on our gas. Now that may not show up on our revenue, like I mentioned on our negative revenue we experienced in the fourth quarter. But basically, it's taking that same inherent energy that's embedded in that molecule, right, and turning it into something that maybe the market would value more. We'll see.

We're excited for it. We think it can make some sense. We've seen some other companies sign up to do something like that as they also have challenges with in-basin gas realizations. As for doing more, man, how much has changed with power in the last 2 years, right? We announced this. And so what I'd say is, I mean, I think we'd like to see how this goes. These are very, very small sites, 10-megawatt compared to the gigawatt type of sites you're seeing now.

Gigawatt plants and data centers are massive operations, incredibly capital intense. You got the hyperscalers now right, committed to what, $600 billion of CapEx combined with them. And then that's all the way up to the President, right? We said, okay, you guys now need to be in charge of your own power. So we're talking big, big, big scale. And then at the same time, that tends with that arena of infrastructure CapEx and investors tends to push down returns.

And so I think for now, we're being cautious and we're waiting to see. We're opportunistic. I mean that's usually the way we treat things. I encourage you to think about it as like opportunistic projects. We did one with midstream. This is another type of project like that is how we're thinking about it for now.

Philip, again, fantastic deal also on the midstream project.

[Operator Instructions] Our next question will come from the line of Nicholas Pope with Roth Capital.

There were some comments made about the New Mexico operations that I guess, in the fourth quarter, maybe even earlier in the third quarter, when the compressor system came online kind of helped boost production on top of artificial lift just downhole work on the wells that have really kind of yielded some real nice results there and kind of maintaining the production levels without a lot of drilling. I was curious like where -- I guess where that New Mexico side kind of is with your taking over operations and kind of some of that field production level optimization right now?

And maybe is there -- do you all think you are fairly kind of through kind of integration of all those assets? Or do you think maybe there's more of that kind of quick hit, low-hanging fruit type production work that you got going to New Mexico?

Yes. I would say related to the fourth quarter, some of the -- there was a couple of early pads that we've drilled that were just outstanding performance, we're really excited about that we've done some testing on. Certainly, we have integrated the Silverback acquisition that's on the west side of our of the Red Lake asset we originally had. We have worked on a lot of integration there. We've combined our workforces got down to 1 office kind of benefited for some water handling optimization, reducing some costs again, just numerous things.

But we do have that, I would say, fully integrated -- there has been some strong work overperformance, which is what we've concentrated on in the early stages of this. We found a lot of low-hanging fruit there wellbore cleanouts, -- we've been switching from some of their artificial lift methods, even from ESP to large pumping units and doing it earlier in their life, and we're saving up to $20,000 a month per installation as we've been able to find those. So we're kind of working through those that's what's been a big contributor to -- like I mentioned, just kind of the outperformance in the first 6 months of Silverback was fantastic, kind of keeping it way flatter than we thought we would, and it's from the strong workover performance.

Got it. And do you think there's -- I mean, are you still finding these opportunities in that area? I mean do you think -- I mean, it didn't seem like there was a big uptick in LOE in the fourth quarter despite kind of the positive number. So I was just curious, like, is that still ongoing? Is there still pretty hurdle ground there to optimize?

Yes, it is. There's certainly quite a few wells. I can't remember how many horizontals they had maybe 3-ish, if I remember right, I met a lot of verticals. But again, we're just prioritizing seeing what's the most effective way to start -- and then, yes, just working through just blocking and tackling with some of these wells, we've been able to restore to near initial production.

So again, it's something that there's not hundreds of them. but we're certainly taking care of them, and that's allowing us to keep that steady and holding that while we develop our what we call kind of our Artesia West on our main Red Lake asset that we've had. So we'll kind of do this in phases from an inside-out approach as we are trying to be effective with Targa's infrastructure. They'll be laying to support this. But we're excited about the large number of upside type things there are here.

That's great. One housekeeping item. The divestiture they all made that non-Jukum County assets. Was there any production associated with that small divestiture.

No, it's a very, very small amount. That was a legacy asset that we brought in. I think progress, if you can go in public, I don't know what the number will 200 barrels Yes, a couple of hundred barrels.

Our next question comes from the line of Noel Parks with Tuohy Brothers.

Just wanted to ask a couple. I think I sort of caught everything from the various moving parts that you were talking about reserves and costs for the reserves for the year. But I -- just -- is there anything about the balance of in the costs incurred between what shows up as under the acquisition side versus the development side? Because the development CapEx is sequentially lower -- well, lower year-over-year by a good bit, of course. And just doing my calculation, it just looked like the 1-year drill bit F&D came out especially low, which is a good thing.

But I just wondered if there was anything sort of unusual about the bookings this year, bringing new areas onto the books and I'm sure reallocating CapEx with the SEC 5-year rule and so forth. So any insight on that would be helpful.

Okay. Noel, I'll take a stab and follow up with you if you need to. The direct answer is that there's nothing nuanced or new going on with regard to how we're booking. I think it's primarily the fact of what Jon described, we had lower activity in '25. Go back to April, May, Liberation Day, prices fall. At the same time, we captured that acquisition, and we try to preserve capital for that. had a little bit of competition for the allocation given the midstream. So we work through the year like that. We're able to grow organically with modest activity like he described, 16.3 net wells put online.

So I think a lot of it is that, combined with the cost savings on D&C. And so that probably translates to what you're seeing in the cash flow statement. When I convert that to reserves. I think we had about $13 a barrel cost to add proved developed reserves on a per barrel basis, not per barrel of oil. And so that was a positive, I think, roughly flat with last year. On reserves, just service announcement for everybody, we aim to take a pretty conservative philosophy of booking. I don't know that we booked a single PUD with Silverback, for example, just being the public company with the SEC in the 5-year rule, as you mentioned, we just find it's easier to book as you go at the kind of minimum. So we focus on predeveloped probably more so than total approved.

Yes, I think that's right, Philip, just with our relatively conservative pace, you could book most of champions as a PUD if you wanted to all but the very Eastern exterior wells, but we've chosen not to do that. New Mexico, until we start drilling more, then we'll be able to expand our PUD base as we start developing more, but we've been limited again with gas takeaway, water takeaway that now has been fixed.

We do pad drilling and so that hurt you from being able to go out and drill 6 different areas instead of 6 wells on the same pad, you can certainly book more PUDs if you do that. But I would agree with Philip where we've taken a pretty conservative stance here, but we have a lot of optionality in the future to improve that.

Great. That does fill in a couple of gaps I had in my understanding. So that's great. And I was thinking just on the question before you were talking about the really nice low-hanging fruit that you have from maintenance, maintenance tasks, workovers, making wellbore cleanups and so forth. And I do recall just, I think, talking about both of your significant pieces of New Mexico acquisitions, especially with the most recent one, Silverback that the assets being in the hands of folks who really were coming from more of a private equity sort of financing background as opposed to being sort of just your typical operators.

As you look around the other vintages of entries into the base in the conventional plays that various parties have done over the last 5-plus years or so. do you anticipate similarly -- I don't know if I call them neglected, but just similar packages out there that have low-hanging fruit that's similar I do recall you saying in the past that the issue is that there isn't really enough upside in a lot of what's been available. But I just wondered if deal something like some back is something that maybe over the next few years, you could replicate easily.

Yes. That's -- there's a lot of different things in there. I think various companies just focus their capital on different things, whether they're trying to drill and flip or if they want to develop it as a legacy asset. I do think our team is particularly good at it. I will say that of recognizing it and then acting on it. But that being said, various companies deal with that in different ways. I think that we can find a lot of fruit in most assets.

But again, we bought Silver back for the most part for all of the drilling opportunity. The -- it's a ton of acreage, right along trend in the Yeso play. That's why we bought it. all of this other stuff with production optimization is just bonus in my book.

Our next question comes from the line of Jeff Robertson with Water Tower Research.

Bobby, you talked about restarting the share repurchase program. Can you just talk about how that plan fits into your overall capital allocation with dividends, debt reduction potential for acquisitions?

Yes. Thanks for the question, Jeff. It basically is just another tool in our tool test to where we look for being opportunistic. If we feel like the share price, which we do is undervalued, it may be behooves to continue more aggressively in a share buyback. Obviously, in these accelerated prices, the returns we get on the drill bit are extremely great for us. So that may not lend to buy back at that particular time. But the fact that we're flexible and can spend our money either to stock buyback or development that's where we want to be.

You saw from the comments and from the falls, I think we averaged the buyback around $26.50 a share or something like that. When the share price is out, I'm definitely buying. So I don't know if I answered your question, but basically, it's there and it's ready when we need it. And if we feel like the return is better on the share buyback than drilling, then that's what we're going to do.

John, in your comments, I think you said -- or maybe, Philip, you said you replaced 2/3 of the 2025 drilled locations for -- I wrote down less than $300,000 per location. Can you provide any color as to where those locations fit in the chart you have on Slide 5, where you talk about locations by return on investment. And then secondly to that, do you have a goal or an objective to how many locations you would like to replace that you'll drill in the 26 program?

I will attempt to answer that. Yes. So the locations, I'd say, they fall in kind of the middle of the 2 to 3x DRI. You're looking at just referencing Page 5 of our presentation, right third, we've got a chart in there. The lower tier there just for the benefit is a small section kind of on the perimeters of Red Lake, but most of our stuff is great, and we're excited about it. This that we got was we think nice down the fairway type of locations, just under a dozen there. So we're thrilled to do that. This might be a Bobby answer, but I'll attempt it. Look, our goal is to would replace as much as we can.

If we could replace 100%, then that's fantastic, right? And in a depletion business, you've got to have something like that, to some degree, the closer you can get to 1x or 100%, that's great. So we're thrilled with 60% last year. Now of course, it was easier coming off of putting on 18 wells versus 40, but we're always out there looking for things. You've seen us have an active A&D track record so far. We'll do the best we can.

Yes. Let me add a little bit to that. we're focusing this year with our land group where we kind of restructured it to 1 of our key focus is going to be what we call the ground game, which is this is not going out and buy a competitor. This is actually just digging in and adding acreage in and around our existing footprint. And the goal would be to replace 100% of what we drill every year or more. And I think we have that opportunity in New Mexico.

We're executing a few of those opportunities in our legacy Yokee this month as we speak. We're a little bit more limited there on where we think the rock creates opportunity than we are in New Mexico. But that's 1 of our big focuses this year is going to be what we call the ground game and executing that. replacing our drilling inventory at least 100% with the bolt-ons.

And Philip, you all Riley signed an agreement with WaterBridge, which I believe takes effect in September of 2026. Will that agreement with respect to saltwater disposal, lower your cost? Will it just improve efficiencies in the Red Lake area? Or how do you -- how should -- how do you characterize that the benefit of that.

Yes. This is John. It's going to increase our cost. But what it does is it allows for full-scale development the rest of the way for this field. So it's -- we did an agreement, I would say, at industry standard rates, and we're really pleased with it. But more than any kind of minor efficiency, it's just like the target is for gas. It's to allow full field development without having to worry if there's any capacity somewhere.

And let me just add on in that what we hope to achieve is that we're managing the costs over time and that we achieve, at the same time, as some of those water bridge costs are impacting us, we get overall efficiencies just with the scale as a larger percentage of the Red Lake production becomes horizontal, which is much higher margin, lower cost versus right now, you've got some component of that that's just, frankly, the vertical that was holding the land, it's how we got it from a seller, right?

Right. And we do have a lot of undedicated acreage at this point. So we still have flexibility for future options as well.

And lastly, Philip, you spoke about hedges for 2026. Given the shape of the curve today where you've got for 2027 prices, I think your oil are in the mid-60s. Can you just provide any color on how you're thinking about hedging in a volatile market.

Yes. So we talk about it approximately 27 times a day and then think about it through the night. We've been through years of volatility, right? We're trying to position ourselves and protect the program ahead. Our philosophy historically is when we've got higher capital obligations and debt loads, then we might benefit from the hedging. We had that as of December. We don't now. But since you hedge in advance, absent liquidating some of those, we have those on the books and I mentioned this in my prepared remarks, we also entered the year with everybody calling for a surplus and $50 or $55 WTI.

So we're happy with where we are. We be happy to write a check to the hedge counterparties if oil is at 70% for many months. We're not holding our breath, and we don't need that to execute on our plan. Like I said, 2/3 of the hedges this year are in the form of swaps with the balance in collars, the callers kind of have a range of weighted average, call it, 58 to 72%. And so we feel good about that. There's plenty of room in there to make some margin.

We -- last thing I'll say is we remember what it was like coming out of COVID in 2020 or coming out in 2021 with the prices rising, and we enjoyed that seeing the daylight and getting that, but we have to be careful to hedge too much as we monitor the cost environment and John's group has to react to potentially changing service costs. Now I think we're in a different environment, and we don't hope to see the same type of of inflation across the board like we did then, which I think was also related to the Fed printing money and so forth. But anyway, that's kind of a long answer of saying we're quite hedged. We feel fine about it. We've got a lot of volumes to work with. We can always do more. We could do less, but feeling good on the setup for now.

Jeff, let me -- this is Bobby. Let me follow up, just to give you a little bit more color on your question on our kind of our ground game and our inventory. One of the things that we're doing here with our subsurface team is really looking at the way our completions in New Mexico through microseismic through different tracer surveys to where we optimize what our wine rack looks like, so to speak. I mean, right now, we have a very conservative approach of about 5 wells, 3 in 1 bench and 2 and another bench. But we're kind of going to where we're going to add a whole another bench in the San Andres and some of our acreage and then modifying possibly by adding a well or 2 per section in the wine rack that we have right now. So that's going to organically increase our well count considerably. When we get to finalizing that. I don't I do know there will be an increase. I don't know just how impactful it will be, but it will move the needle there.

Yes. And that spacing you were mentioning is 320.

Yes. Okay. Those would be locations added on existing acreage. So there's really no incremental cost.

No incremental cost in the acreage, that's correct.

This concludes the question-and-answer session and our call today. Thank you all for joining. You may now disconnect.

Ladies and gentlemen, thank you for standing by. Hello. My name is Dustin, and I will be your conference operator today. At this time, I would like to welcome you to Riley Exploration Permian Inc. Third Quarter 2025 Earnings Conference Call. [Operator Instructions]

I would now like to turn the conference over to our CFO, Philip Riley. Please go ahead, sir.

Good morning. Welcome to our conference call covering our third quarter 2025 results. I'm Philip Riley, CFO. Joining me today are Bobby Riley, Chairman and CEO; and John Suter, COO.

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. We'll also reference certain non-GAAP measures. The reconciliations to the appropriate GAAP measures can be found in our supplemental disclosure on our website.

I'll now turn the call over to Bobby.

Thank you, Philip. Riley Permian delivered another solid quarter marked by disciplined execution and strategic progress on multiple fronts. In July, we closed the Silverback acquisition and began integrating the asset where we are already realizing synergies. In just a few months, we have reduced costs and increased production. For September and October, combined production on the acquired asset exceeded our underwriting case by more than 50%. We executed our development and capital plan during the third quarter, which contributed to significant free cash flow generation.

Over the last 9 months, we have generated $100 million of upstream free cash flow, approximately flat compared to the same period a year ago despite a 14% lower realized oil price. We continue to progress our midstream and power generation projects, securing equipment and advancing build-outs. These critical infrastructure projects should enable Riley Permian to scale operations in 2026 and beyond.

Today, we are paying our 19th consecutive quarterly dividend as a public company. In October, we increased the dividend to $0.40 per share, up 5% from the previous quarter. Maintaining a consistent and growing dividend underscores our commitment to capital discipline and focus on sustainable free cash flow.

With that overview, I'll turn the call over to John Suter, our COO, for operational highlights, followed by Philip Riley, our CFO, who will review financial performance and forward-looking guidance.

Thank you, Bobby, and good morning. Riley Permian has once again shown its commitment to safe operations, achieving a total recordable incident rate of 0 in the third quarter. We achieved 93% safe days, a metric requiring no recordable incidents, vehicle accidents or spills over 10 barrels. As for activity, in the third quarter of 2025, we completed 5 and turned in line 10 gross operated wells. 5 of those wells turned in line were completed at the end of the second quarter.

Average daily net production was 18,400 barrels of oils per day and 32,300 barrels of oil equivalent per day for the third quarter of 2025. Oil volumes increased by 3,200 barrels per day during the quarter, benefiting from the addition of acquired Silverback volumes, incremental production gains from Silverback workovers, along with strong performance from several new wells on legacy acreage.

Total net oil production increased from 1.38 million to 1.69 million barrels of oil quarter-over-quarter in Q3. This is an increase of 22% quarter-over-quarter and an increase of 19% compared to the same quarter last year. Total equivalent production is up 34% quarter-over-quarter from 2.22 million to 2.98 million barrels of oil equivalent and up 38% compared to the same quarter last year.

Total equivalent volumes grew faster than oil last quarter for 2 reasons: First, because our Texas midstream partner completed some upgrades, which led to materially more gas sold; and second, with the contribution of the Silverback asset, which has a gassier mix currently. This will become more oily as we bring on new horizontal wells.

At Riley Permian, we pride ourselves on being a low-cost operator. We nearly doubled our operated well count in New Mexico through the Silverback acquisition. Many of the acquired wells are lower volume vertical wells with a higher cost per barrel. However, we maintained LOE per BOE near $9 per BOE, which is only a 6% increase over Q2 and a 5% increase over the same quarter last year. We believe we can reduce costs further as a result of synergies we're realizing through the Silverback acquisition that we'll discuss shortly as well as increasing the mix of horizontal wells as we continue to develop.

Riley Permian picked up a drilling rig in October, getting a head start on our development for 2026. We are drilling 8 to 10 gross wells in Q4, which will set us up for some early completions in Q1 of 2026. In addition to the drilling program, 3 to 5 gross operated wells will be completed in Q4, cementing a solid exit rate for 2025 and base production for the year to come. Our initial look at D&C pricing for the upcoming wells in our Red Lake asset is down nearly 10% over our last campaign in New Mexico. This is the result of softening of prices in both rigs and frac spreads as well as lower steel prices than realized earlier in 2025.

Moving to midstream. Our gathering and compression project in New Mexico continues to add value in the form of increased flow assurance by reducing downtime and allowing us to bypass some of the legacy low-pressure systems in the area that struggle with reliability. In the fourth quarter, we plan to upgrade the initial compression facility we installed earlier this year with an incremental 40 million cubic feet per day nameplate compression capacity. This will allow us to utilize 15 million cubic feet per day in addition to what we're currently delivering to our existing provider, and we'll be able to utilize all remaining high-pressure capacity when our transmission line is in service in mid-2026.

Low-pressure gathering lines are currently being installed to expand the input capacity to the compressor facility, allowing us to utilize the additional capacity that we will have by year-end. The high-pressure transmission line we're planning to install continues to progress. Permitting is submitted and underway and secured pipe is scheduled to arrive late in the fourth quarter or during the first quarter of 2026.

Shifting to power. Our joint venture, RPC's project in Texas continues to grow in scope and improve in reliability. In the third quarter, we added 5% more of our total load to the generation in Texas with 100% uptime in September. In New Mexico, RPC is progressing on the plans for another behind-the-meter generation project. We've begun permitting, designating a location and securing long-term lead items, including 10 megawatts of generators. The pilot generation station as well as the distribution system will begin construction in 2026.

We continue discussions to advance both water and oil infrastructure projects that will maximize our ability to control development pace. We also look forward to better realized pricing on our oil barrels as we consider moving away from trucking where opportunities exist. The Silverback acquisition is already realizing value through synergies and cost-saving opportunities since closing. We've been able to drive down fixed costs in the field through things like combining multiple field offices and managing headcount. We expect that those fixed costs will come down 10% to 20% following those and other changes. We mentioned last quarter that we intended to leverage our expertise in water handling to drive down costs in both Silverback and legacy Red Lake assets. In a few short months, we've seen a $70,000 per month decrease in costs due to our integration efforts.

We're nearing completion of low-pressure gathering lines that will tie back some of the gas in the Silverback acreage to our compressor station we've built, allowing for better reliability, maximizing production from the area. Significant progress has been made in maximizing production from the asset. Without bringing on any new wells, the Riley Permian operating team has increased production over the purchase case forecast by over 50% for the months of September and October combined. This was achieved primarily through strategic workovers, returning wells to production as well as artificial lift optimization.

We're pushing forward with several RFQ processes, attempting to leverage the larger economy of scale achieved through acquisition. We anticipate notable savings on frequently used materials such as steel tubulars and production chemicals as a result. Overall, it's been a very successful quarter for the operations team. We're progressing our efforts on both our midstream and power endeavors. We're already seeing costs come down on our latest drilling program. We're maintaining disciplined operating costs and all of this while achieving record levels of production. Congratulations to the team on a job well done.

Philip, I'll now turn the call back to you.

Thank you, John. Third quarter results reflect the Silverback acquisition given the deal closed on the first day of the quarter. The transaction was accounted for as a business combination. Cash paid at closing was $120 million, 15% lower than the $142 million unadjusted purchase price upon announcement, benefiting from cash flow from the January 1 effective date through closing as well as other favorable adjustments. Overall, company third quarter results were either within or favorable to guidance levels.

Prices after hedges were roughly flat quarter-over-quarter and oil represented all of our revenue last quarter as we experienced negative natural gas and NGL revenues after fees. As discussed by other operators reporting recently, the industry experienced an especially weak September and October gas market in the Permian with select operators voluntarily shutting in an estimated 1.5 to 2 Bcf a day of gas production. LOE was higher quarter-over-quarter, driven by 2 primary factors. First, from the contribution of higher cost Silverback vertical wells that John discussed earlier and as I previewed on the second quarter call; and second, from increased workover activity associated with the positive results John described earlier, which drove higher corresponding workover expense.

A quick clarification is in order here. Investors often associate most dollars spent supporting new production volumes in the form of capital expenditures, while we often opportunistically pursue workovers like these, which get expensed and are embedded in LOE on the income statement. Production taxes were higher as a percentage of revenue as more volume shifted to New Mexico, which has a higher tax rate than Texas. Third quarter administrative costs included transition costs associated with the acquisition and other nonrecurring items, which should normalize over time. On a per BOE basis, costs were squarely within the guidance ranges for LOE and administrative costs.

We had nearly $5 million of favorable income tax benefits in the third quarter resulting from the new federal legislation, allowing for increased bonus depreciation, which we realized across our legacy assets, the acquisition and from our midstream project. Third quarter cash flow from operations before changes in working capital was $54 million, higher by 17% quarter-over-quarter, primarily from higher volumes and from slightly higher oil prices before hedges.

Adjusted EBITDAX margin was 59%, down from 66% last quarter, primarily as a result of the cost items noted above. On costs and margin, consider that we've just closed the Silverback acquisition. Our team has made good initial progress and is excited by the potential to drive synergies and develop the asset. We're optimistic to lower our cost structure and improve margins over time. We take confidence in this potential given our track record in this area. Since the Pecos acquisition 2 years ago, we've reduced LOE per barrel for that specific asset by more than 30%.

During the third quarter, we reinvested only 27% of cash flow from operations before working capital and upstream CapEx or only 36% for the 9 months year-to-date. Third quarter upstream accrual-based CapEx was nearly 40% below midpoint guidance as a result of some delayed non-op activity and infrastructure spending. Some of this will be shifted to the fourth quarter.

We generated a very robust $39.4 million of upstream free cash flow in the third quarter, representing 73% conversion of operating cash flow before working capital. Year-to-date, we've generated $100 million of upstream free cash flow or 64% of free cash flow from operations, an amount equal to the same 9-month period for 2024 despite 14% lower realized oil prices. On our other projects, we invested $14 million in our New Mexico midstream project. And in power, we invested $8.5 million with the latter -- into the JV, with the latter being slightly over guidance as we simply accelerated most of the fourth quarter spend to secure some equipment. Year-to-date, we've allocated 31% of total free cash flow to dividends. Debt was $375 million at quarter end, corresponding to 1.3x leverage based on pro forma adjusted EBITDAX, including Silverback.

Now I'll move to guidance. We're raising oil production guidance for the fourth quarter by 4% at the midpoint to 19,200 barrels a day. This fourth quarter oil production rate at the midpoint corresponds with 5% quarter-over-quarter growth and 21% year-over-year growth from the fourth quarter of 2024. This leads to a 2% increase in guidance at the midpoint for full year oil production to 17,100 barrels a day, corresponding to 13% year-over-year volume growth.

We're maintaining guidance for full year total CapEx and investments at the midpoint at $92 million of accrual CapEx with some shift in spending from third quarter to the fourth quarter. The combination of increased production with flat CapEx evidences doing more with less. Fourth quarter drilling and completion activity will primarily drive 2026 results with only modest impact on fourth quarter volumes. D&C cost savings in New Mexico and some schedule flexibility allowed us to accelerate 2 completions from 2026 into the current quarter. These wells will support 2026 production with no impact to fourth quarter 2025 volumes.

Looking to next year, we're striving to balance excitement around development potential in our asset base with capital allocation discipline in the face of softer oil markets. While some longer-term planning commitments are required, we'll watch the markets and aim to maintain flexibility with shorter-term commitments. We believe the current state of the oilfield service market affords such flexibility. Fortunately, we're in a situation that allows for resiliency and confidence across a range of prices. I'll offer the following examples based on preliminary forecasts. We believe we could maintain our third quarter 2025 oil volume level of 18,400 barrels a day over the full year in 2026, which would equate to 8% year-over-year growth while reducing 2026 upstream CapEx by approximately 15%. This scenario partially benefits from the fourth quarter 2025 forecasted volume tailwind of 19,200 barrels a day at the midpoint.

Next, if we focused instead on maintaining upstream CapEx and not volumes, then we believe we could keep our 2025 upstream CapEx level generally flat while growing full year oil volumes year-over-year by approximately 12% to 15%. If oil markets improve, we can grow beyond these levels with increases in capital spending supported by our deep inventory of development locations.

Finally, we forecast the dividend being well covered across these 2026 activity and oil price scenarios, benefiting from this capital efficiency and hedges in place. We have over 60% of 2026 oil volumes hedged at a weighted average downside price of $60 with upside optionality as 44% of hedges are in the form of collars.

I'll turn it back to Bobby for closing. Thank you.

Thank you, Philip. Once again, we appreciate your time and interest in Riley Permian. While we're pleased with our Q3 2025 results, our focus remains firmly on the future. We are committed to creating long-term value through disciplined capital allocation, strategic infrastructure investments and operational excellence. We believe these initiatives will position us for sustainable growth and shareholder value. We appreciate your ongoing support and confidence in Riley Permian.

Operator, you may now turn the call over for questions.

[Operator Instructions] And we will take our first question from Derrick Whitfield from Texas Capital.

Congrats on a solid overall print. Wanted to start with a bigger picture question on capital efficiency and capital allocation. As we think about Slides 5 and 7 and Philip's ending commentary, it's clear your business has differential capital efficiency and can accomplish an all-of-the-above funding strategy while continuing to grow in a relatively low to mid-cycle pricing environment. As you think about your cash flow priorities in a below $60 per barrel environment, how would you prioritize capital allocation in that environment? And are there pathways where you can continue to fund all 3 segments of your business while maintaining control of each?

Yes. Fair question. Thank you, Derrick. In a $55 scenario, that starts to get to the point where on a corporate level, full cycle, we're mindful of spending too much. I think our half cycle economics, as evidenced there on that slide you referenced, can work down below $40, but there's no pressing need to develop that sooner. So I think in a $55 scenario, you're going to see us in that lower potentially volume maintenance scenario where we're spending sub-$100 million, maybe it's in the $85 million range. We can maintain volumes that way.

We've got the dividend well covered. I think we are funding CapEx for the midstream find that way, and I can talk more about that in a bit, if you like. But that's probably a fair inflection point. I think there's also probably some psychology bias there at that inflection point of $55. Things below it start to get tougher for our industry. That said, it's never just a single variable equation. We'll see how the oilfield services market reacts. Some believe that their costs won't go lower, but you never know. Should those continue to decrease, then that can change some of the economics as well.

Terrific. Yes, that makes sense. And maybe for my follow-up, I wanted to shift over to the New Mexico Midstream project. While the ability to control pace of development and flow assurance are the primary drivers, could you offer some color on the potential improvement you'd expect in netbacks for the upstream business and the amount of third-party volumes that could accrete value for the midstream business?

Yes, I can start and then maybe, John, if he wants to fill in on some of the volumes. Look, on netbacks, this is never a binary clear impact. I think the way that works is, first and foremost, we start with the flow assurance. We're getting into good systems there, newer generation gathering compression pipe and their facilities. We think we're going to get some economic improvement based on more efficient, best-in-class type of processing and treating facilities. So we've got some of that modeled that we hope to realize. And then the netbacks themselves, sometimes what that involves is making an additional commitment to get to capacity basically by your way into some capacity that reaches the Gulf Coast.

You see some companies -- I think there's a company hosting a call at this exact time that's done that, where you make a commitment to the midstream counterparty for that capacity, and they can offer you a bit closer to the ship channel pricing. Now there's a negotiation involved. And not everybody can do that because clearly, most of the Permian would like to have the ship channel versus the Waha pricing. But I think it represents a spectrum. We hope to get some of our gas closer to that, but it will be something that takes place over time.

Yes. Derrick, I'd like to add from an operational perspective, I think this midstream project is just a must-have for our company to be able to grow the New Mexico asset. I think not only are we going to get a little bit better processing outcome from the new provider, once we put about $15 million more into the -- as I said in our initial discussion, that will be all that current provider can handle.

And so there will be -- without gas decline, there will be no more room. So this really allows us with $150 million to $200 million more capacity within this new line I mean it's going to let us do what we're -- our main objective to drill oil and gas wells. We'll have a home for our product. So it really is a must-have. Again, we can -- right now, our pace is very limited in New Mexico just because of that. So given that new capacity opportunity, then we can make the choice as commodity price swings, as our value from making more oil and gas is enhanced, we can step it up and fill that need quickly.

Our next question comes from the line of Jeff Robertson from Water Tower Research.

Bobby, maybe to follow up on your last comment is essentially the midstream project, once it's completed, will allow Riley to produce more oil because you can more -- you can pace the development of your field however you see fit with commodity prices since that's where the -- at least currently, that's where the real value is. Is that the right way to think about it?

Absolutely. I think that was John that was talking there, but he's right on point. I mean, our objective is to get unconstrained takeaway capacity for both gas, oil and water so that we have full flexibility in our pace of development to develop the asset. I mean we've been drilling some pad locations with anywhere from 3 to 5 wells coming on at the same time. So it's a substantial bump in all of those -- that commodity mix all at one time. So the track we're on is just to get us in a position to have all options on the table.

Philip, can you talk about the capital spend for the midstream project completed in the first half of 2026 and then how that impacts your free cash flow flexibility in the back half of the year with that burden behind you?

Yes, sir. So I think this weaves into how I -- in my prepared remarks, talking about some of those maintenance scenarios and the level of spending there. If you look at what we've disclosed in the very beginning of 2025, we saw spending roughly $130 million on this midstream project to get it completed with the pipe and through initial areas in our kind of core development area.

Since buying Silverback, we could expand that, but we don't have to do that right away. So we're considering a number of options, Jeff, if we bump along in this kind of $60 level or even a little bit low, we're going to be watching the prices and watching our cash flow. We could maintain the status quo and keep this on the balance sheet. I think based on the scenarios I described, we can be roughly free cash flow positive even after combined upstream and midstream CapEx. So maybe that's somewhere in the $170 million to $180 million range or possibly just short after the dividend at kind of $60 WTI, in which case, you've got a slight deficit there, but you've got plenty of capacity because you are creating value. So we take comfort there because we've created real asset value. We've got an implied $120 million, $130 million of spend there into the midstream at that point.

And so because of that, I guess I could segue, we're also considering some financing options at the project level. We've considered using a credit facility. Our existing credit facility is an RBL, reserve-based loan. It allocates 0 value to the midstream assets right now because it's all about the upstream reserves. But there very much is material hard asset value there. As I just described, it could be a cumulative basis, $120 million, $130 million of book value by the end of next year if we proceeded with that. We've also considered bringing on an investor partner, which could take different forms. And so we've had those and other options that we're working through. We take confidence that we have a number of alternatives. Nothing has been definitively decided at this stage.

So if you went some sort of project route and any economic benefit from third-party volumes would flow through that type of entity. Is that right?

Yes. And just to be clear, I'm talking more capital partners, Jeff. We can -- we could have third-party operators that could come through the pipe, and we could sell them some capacity, in which case we're collecting more fees. That's something that's possible, too, and that's something that helps with -- that's something that would help with revenue and cash flow over time, but not with the upfront capital to build the project. That has its pros and cons. Pros is you got true third-party incremental revenue there.

The balance is with Silverback and the size of our footprint now, I mean, we see potential to fill up the entire capacity by ourselves. Now that takes time to do it, maybe it's 7 or 8 years. And so the question then is, do you sell some of that capacity for a shorter-term basis? Do you sell it for a longer-term basis at a higher price? Do you expand this and so forth. So it's kind of an organic thing that we're working through. But going back to the capital, we'd be looking at some capital type partners that could come in different forms, whether it's an equity or credit.

And lastly, on production on the Silverback assets, John or Bobby, is there more to do on those assets to continue the solid performance that you had in September, October in terms of workovers and lift optimization and those types of projects? Or have you done the most obvious projects to this point?

Yes. This is John. No, I would just say we've barely touched it. We've just gotten some obvious things where wells were offline when we took it over. They had gone through this divestiture process a while. So missing a little TLC that we have found just some easy things to do, but we've also tried bringing over some of the more technology based, the way we do our cleanouts that we think are different from what other people do and have had some really nice success on a couple of those. We obviously have several hundred wells that we can work on. I think there's probably like 30 horizontals and upper 200s of vertical wells. So there's quite a bit of playground there. We're frankly just very excited about it.

Our next question comes from the line of Nicholas Pope from ROTH Capital.

I was hoping you could expand a little bit on that last question. Just kind of looking at the workover, John mentioned that, that was a part of operating expenses being a little up for the quarter, just a lot of opportunity. Just trying to quantify a little bit how much, I guess, workovers were as a percentage of like total operating expenses for the quarter and like how you anticipate that split of OpEx kind of over the next year or so?

Nick, I'll take a first stab at this. I think this quarter, it was a few like probably $3 million -- $2 million to $3 million higher than normal. The reality is this is always in there. Sometimes it's a nature of our wells versus a shale, but we're always doing workovers. Last quarter was relatively light. And this quarter, we did more. You only see that on the line called lease operating expenses. But I think we had something like $8 million to $9 million total here of workovers. And so on an incremental basis, that was probably $2 million to $3 million higher than the prior quarter.

Yes. For instance, workover was 59% of total LOE this quarter versus last quarter, 27%. And I think it tends to range more in the 45%, 50%. So really, there was, I think, $5 million. Silverback came in at around a $13 per barrel cost versus our 2 assets typically average more in the $8.50 range. And so that kind of tells you how that blended up to a little bit over $9 per BOE total LOE with, again, workovers being typically 40% to 50%.

And just to add a final point there, just how we manage the groups is that this is a mix of reactive and proactive work. Reactive is something shut is down, and it's a big miss. But proactive to go out and do these exciting projects, the groups are given a budget and we can monitor with real-time analytics and stuff, how our costs are coming in for the month, and so they have certain budgets to work with. And that's a way we can have that vacillate from quarter-to-quarter, but then come out smooth on the overall cost per BOE.

That was very precise. I appreciate it. Looking at the activity, no drilling this quarter, bringing the rig back, I guess where is the focus of kind of that near-term drilling with the rig coming back to start drilling right now?

Yes. So we're over in champions in Texas. Like I said, we've got 8 to 10 wells coming by year-end. This will kind of refill our inventory of DUCs that we will use to complete -- gives us a great bit of flexibility with this whole commodity price challenge. So we'll be able to frac these things as we need them, kind of move that throughout the year depending when the markets are in our favor. So we have that. And around the turn of the year, we will shift our focus to New Mexico, and we will plan to start drilling a program there. I think we've only drilled 12 wells in New Mexico in the last 1.5 years that I've been here, and we've had some great results there so far. So I'm excited to get back and prove out some more territory there.

And then on the turn-in lines, Nick, the first half of the year next year will generally be Texas. The second half then would be New Mexico contingent on our pipe coming online around midyear. Again, we've got that flexibility with the DUCs, as John described, to throttle those more or less based on price or if things are faster -- if the project is faster or slower around the midyear.

[Operator Instructions] Our next question comes from the line of Noel Parks from Tuohy Brothers.

I was interested to hear your thoughts earlier about some external financing possibly being in sight. And we're in such a sort of unusual uncertain macro environment and interest rate environment. And I was just wondering, as you consider that project level financing, are you talking to pretty much usual suspects, the names we would kind of all be familiar with? Or I was wondering if you're seeing interest or capital coming in from more unexpected players or new players?

Sure. Let me take and respond to the first half of the question, which I think was a comment about the uncertain macro and economic situation. I admit and agree that the upstream energy industry is out of favor at the moment. It's a tougher situation on the equity markets. Credit markets, whether for upstream or the wider market are very, very healthy right now. This is on the upstream, just real quick. We've had a lot of consolidation. So a lot of paper has come off from the banks. They are really wide open lending. High-yield markets, bond markets are wide open again, generally and upstream, we've got some very, very low spreads. That's not exactly what we're looking at here, but it just gives some context.

What I'd also say is, aside from just pure upstream, there is a tremendous amount of appetite for capital for interesting new projects, infrastructure projects. If I go to the extreme, we look at what's happening with the hyperscalers, AI and data centers, and you see the tremendous amount of capital being thrown at that. Well, that's -- we're on the spectrum there of an infrastructure asset midstream being much easily -- more easily financed than upstream typically. We've got some real hard asset value here. We're going to have some contracted volumes and values, and that's something that you can lend against.

Like I said, the credit facility currently has 0 allocated value for that. And so there's some debt capacity there. So just one example to start is just a plain vanilla bank is happy to do some lending there. Down, we don't talk about it because it's not in our financials directly, but our JV partner or our JV, RPC Power, has a plain vanilla credit facility with a regular way bank for financing some of that. And that's 7%, 8% cost of capital. Something like that could be available for midstream or if we wanted more capital, we could bring in a type of private capital investor who could be investing in some kind of common or preferred if we structured it that way at the midstream level.

You can go look at case studies of different groups that have done this at those midstream projects. Private capital providers are excited to do this. I'm probably going to get a lot of calls after this is done just for saying this. But yes, they're excited to do that, and that represents something between credit and equity. And then you've got just pure common equity if you wanted someone to be really investing all of it. I hope that helps.

Very much though. Sort of staying on that topic of where there's a lot of interest these days. I'm just curious, compared with a few years ago when you decided to go forward with the power JV, mainly with an eye to your internal needs, first and foremost. And today, when it seems now that the sky is the limit for any sort of gas-fired generation any place, anytime, anywhere these days. Just wondering if any conversations you're having on the power side, maybe around local generation or regional generation for possible data center projects and so forth. Just wondering how the environment and the conversation is different now compared to when you were first going forward with the project.

Right. So we're very grateful that we got in, feel fortunate that we started this over 2 years ago, nearly 3 years ago at this point. So clearly early there. And clearly, the environment is very, very different now, both nationally and in West Texas. And so some of that, we feel happy to have the thesis validated, but ultimately, that doesn't matter, and we just want to make money. On new projects, look, we're -- I think we're taking a balanced approach. We've got a relatively full plate at the moment, but we're always looking for new places to invest our time and capital if we think we can earn a good return. Just to be a little cautious with so many people coming into the data center space, we want to be mindful of what incremental value can we add there.

And then on a return of capital and cost of capital, typically, the more people you have to come into something, it gets crowded, it pushes down returns. We just have to be sufficiently comfortable and confident that we can earn a return of capital there. That competes with our core business and such. And then finally, if it's something that we did want to do, do we do it as a developer and so that you're getting this up to a certain critical stage and then effectively sell it versus if you decided to keep it on the balance sheet in perpetuity, we would have to believe that we get re-rated and that analysts like you suggest that we should be rerated to trade at a higher valuation because that would be embedded in our -- what's typically a lower valuation type multiple for, say, an upstream company versus an infrastructure or an IPP, which are trading at 12 to 15x EBITDA.

Right. Okay. That makes a lot of sense.

There are no further questions. That concludes our question-and-answer session, and that concludes the call for today. Thank you all for joining. You may now disconnect.