Riley Exploration Permian, Inc.

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 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 gap 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, helps 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 Thank you for joining us. and improve 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 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 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 begin 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 cost 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. 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 work over execution. There are a few specific examples worth highlighting. 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%. 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 doubled. Where the buy side case projected 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, 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. Thank you for joining us. 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 state 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 Thank you for joining us. 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 target line, water bridge 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. Hi, everyone. 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 in the commercial service midway through the second quarter, and we began selling in the ERCOT stay-ahead and real-time markets. The second side is finalizing commissioning, currently selling into real-time markets, while a third side 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 multi-year lows following a surge in solar supply, and new large-load interconnections are stuck in the queue. But a 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 in 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 25.6,000 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 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 in the 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. And everyone, at this time, we will take your questions. If you have a question today, please press star 1 on your telephone keypad. Your first question will come from Derek Whitfield, Texas Capitol.

Good morning, guys, and 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. 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 similar trajectory headed into 2027. 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?

Derek, 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 one rig running now continuously. So, you know, without any unforeseen hiccups in the current markets, you know, 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. So I don't see anything too different next year than where we are today.

Terrific. And then maybe just on the follow-up, kind of leaning in on Champions, if I could, what you're highlighting on Slice, I think it is 10 of your deck seemed exceptionally capital efficient in terms of drilling production. How should you think about the depth of work over opportunities you have as champions and how you plan to center those into your development plans?

Yeah, 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 you know 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 you know there's potentially a couple 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. 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 that you also have the benefit of that from those barrels that are added.

Perfect. Thanks and great update.

Your next question today comes from Neil Dingman from William Blair.

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

Now 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. 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, I We do have what we can control, which is this nice inventory to draw down.

Great point. And then just to 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? And if there is, are there things that you're doing to continue to minimize that?

Yeah, I'll take the first part of that. You know, from a gas takeaway, like we said, we believe that TARGA line will be in very early fourth quarter. Up until then, you know, 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 1st 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.

Yeah. You know, 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. 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 large projects come on the last two months, and price has rebounded. The Waha Prize 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 soon. 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.

Great details. Thanks, Bobby. Thanks, Bill.

As a reminder, everyone, it is SAR 1 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 work over activity that you all have performed?

You know, I think we've picked off some really obvious ones. I think there's certainly more work to do. You know, we haven't even tried pushing some of this Surface Acid 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 pre-cash flow is going to be 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 pre-cash flow and with respect to returning cash to shareholders, trade-offs between repurchasing shares through the authorization and the dividend?

Yeah, 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 in the next year is going to translate into higher production, which, you know, depending on oil price, it's going to be very positive for us. But, you know, we just have the choices. Stock buyback seems to be one of them that 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 kind of continue as we've been going. Our debt right now at 1.0 times leverage is reasonable. We can continue to pay that down and will as a potential source of that – our use of that cash. I don't know. Phil, 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 know, you can 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 two quarters and the year ahead. Thank you.

Your next question is Noel Parks, William Blair.

Hi, good morning. Noel Parks with Two New Brothers. You know, I was wondering if you could maybe just refresh my memory on sort of the back story of the more complex wall designs you mentioned. And I was just trying to recall whether that's sort of like 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. You know, but you have quite a few, you know, five, six wells in a 320 acre unit. 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 U-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 Yeah. Yeah. We are studying that right now. We generally will have two wells in the paddock and maybe three in the blindberry. We're also taking a look, you know, our technical team now of the San Andres and the lower blindberry. You know, 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.