REPX

Good day everyone. 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, CFO. 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 and 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. 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 24.4 thousand 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 2026 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 zero 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 one SWD, improved average lateral footage per day by 19%, and reduced drilling costs per lateral foot by 7.5% compared to 2025. We also set new Yoakum County records for both one mile and one and a half 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 costs per lateral foot by 32%.

We also successfully executed the first mile and a half 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. While operating costs were up quarter-over-quarter, a large portion of that increase was tied directly to projects that improved production, enhanced runtime, 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 runtimes 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 two 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, well bore 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 interests, 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 four-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. We do expect it to create some upward pressure on LOE over time. 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 continued 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 Targa line, 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. 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. Summer power prices are at multiyear lows following a surge in solar supply, and new large load interconnections are stuck in the queue. The long-term thesis remains an interesting option to monetize undervalued Permian gas. 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. We're guiding to $59 million of accrual CapEx. 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 25.6 thousand 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-$236 million. Roughly a third of the increase is associated with upstream activity, and two-thirds 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. Both 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.

Thank you, sir. Everyone, at this time, we will take your questions. If you have a question today, please press star one on your telephone keypad. Your first question will come from Derrick Whitfield, Texas Capital.

Good morning, guys. Congrats on a positive quarter despite the many headwinds you faced.

Thank you.

I wanted to start with your outlook and some of the comments you made in your prepared statements. I realize you're not providing 2027 guidance today, the heightened activity of your 2026 capital plan and the potential of your workover opportunities at Champions seemingly places you on a similar 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 see us having a pretty steady pace of development, and we have one rig running now continuously. Without any unforeseen hiccups in the current markets, I just think that we're steady as she goes. We're a growth company. We intend to grow production year-over-year, spend within our cash flow, reduce debt, pay dividends. I don't see anything too different next year than where we are today.

That's terrific. 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?

Yeah. 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. 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. There's potentially a couple years of inventory right there. New Mexico, we've done some of this, but really there's a lot more wells there to try this on as we grow. I think we do have a good inventory of it. Like I said, that's pretty easy to feather in. 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 that you also have the benefit of that from those barrels that are added.

That's perfect. Thanks and great update.

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

Good morning, all. 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 or M&A growth externally from each other? If you grow it organically, is that going to limit how much M&A? Maybe just talk about how you think about capital allocation for the two.

I can 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. Ultimately, that's out of our control. It was, for the market in general, quite a quiet quarter in the second quarter. 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. In the meantime, we do have what we can control, which is this nice inventory to draw down.

Great point. 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? If there is, are there things that you're doing to continue to minimize that?

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. Again, here it's already August, and we believe we do have some of that under control. Really we just need to get to October 1st and we should be in good shape, we hope. I'll hand it to Philip to talk about some of the FT type stuff.

Yeah. When we talk about infrastructure constraints, I know it can be confusing given it permeates the discussion both within our micro situation and in 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. 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 the last two 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. It seems to be a combination of some really hot weather at the same time, 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, that should be coming back. The pipes, those new projects appeared to have filled up very quickly, and yet price remains pretty high. 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. We shall see. A lot of the bigger power projects have been slower to come on, some of that burn has been slower. That's our point of view at the moment.

Great details. Thanks, Bobby. Thanks, Phil.

You bet.

As a reminder, everyone, it is star one to ask a question today. Next up is Jeff Robertson, Water Tower Research.

Thank you. Good morning. 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 costs on those assets through some of the workover activity that you all have performed?

I think we've ticked 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 chemical injection projects over in New Mexico. Not many of those. We think there's still a lot of running room with that. Again, we feel really proud of that since we haven't even drilled any wells there yet. 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. We've done some great workovers, 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 expected to increase in the second half of the year. 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?

I think our main focus is to remain flexible with having all those choices in front of us in any given quarter. Obviously, we've been paying dividends. We've been growing our dividend year-over-year. I expect that trend to continue. I think some of the money that we're spending this year and early in the next year is going to translate into higher production, which, depending on oil price, is going to be very positive for us. We just have the choices. Stock buyback seems to be one of them, and we've used it and will 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 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 our use of that cash. I don't know, Philip, what do you think?

Yeah. 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 with 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's 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.

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. We feel good about it looking at the forecast, and excited for the next two quarters and the year ahead.

Thank you.

Your next question is Noel Parks, William Blair.

Hi, good morning. This is Noel Parks with Tuohy Brothers. I wonder if you could maybe just refresh my memory on sort of the backstory of the more complex well designs you mentioned. I was just trying to recall whether that's sort of just geosteering to stay in zone or more like U-shaped lateral designs for when you don't have the adjacent sections to extend them into.

Yeah, Noel. 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, five, six wells in a 320-acre unit. Also working around fields that have vertical wells in it. It just makes a little bit more complex designs. We would love to be able to do some of those U-turns and different types of wells that make a lot of sense in deeper horizons. I remind you that in New Mexico, we sit at about 3,500 feet, and in Texas about 5,500 feet. 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 well bore avoidance.

Right. Just another thing. Could you just sort of maybe iterate on where things stand as far as just your well spacing in New Mexico?

Yeah. We are studying that right now. We generally will have two wells in the Paddock, and maybe three in the Bone Spring. We're also taking a look, our technical team now of the San Andres and the Lower Bone Spring. 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.

Great. Thanks a lot.

Everyone, 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-