Riley Exploration Permian, Inc.'s Third Quarter 2026 Earnings Conference Call - RILEY EXPLORATION PERMIAN INC

Hello, everyone. Thank you for joining us and welcome to Riley Permian Inc's third quarter 2026 earnings conference call. After today's prepared remarks, we will host a question and answer session. If you would like to ask a question, press star one to raise your hand. To withdraw your question, Press star one again. I will now hand the conference over to Ben McQueen, VP strategy and investor relations. Please go ahead. Good morning. Welcome to our conference call covering our third quarter 2026 results. I'm Ben McQueen, VP of Strategy and Investor Relations. Joining me today are Bobby Riley, Chairman and CEO, John Suter, COO, and Philip Riley, CFO. Yesterday we published a variety of materials which can be found on our website under the Investors section. These materials in today's conference call contain certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Potential drilling locations that will be discussed are based on management's internal estimates and are not proved reserves. As of today, no proved reserves have been attributed to these locations. Whether and when they are drilled will depend on several factors, including commodity prices, capital availability, drilling and completion costs, regulatory approvals, results of offset and delineation activity, and other factors. Actual drilling activity may differ materially from these estimates. We'll also reference certain non-gap measures. The reconciliations to the appropriate gap measures can be found in the supplemental disclosure on our website. I'll turn it over to Bobby. Thank you, Ben. The third quarter was an exciting quarter for Riley Permian as we continue to execute on the development program we have discussed throughout the year. Much of the activity completed earlier in 2026 translated into production during the third quarter, resulting in the significant step up in volumes we had anticipated. Oil production averaged over 25,000 barrels per day, an increase of 20% from the second quarter and 38% from a year ago. Total production increased 23% sequentially to approximately 42,000 BOE per day. Importantly, we delivered that growth despite wells turned to sales coming in below the low end of our guidance range. Those results reinforce our confidence in both the quality of of our asset base and our ability to execute our development program efficiently. One area that I want to spend some time on today is an additional resource opportunity we have been evaluating at Red Lake. To date, our development activity at Red lake has primarily focused on the paddock and blind brief formations part of the YASO package. We are now preparing to expand that activity into the San Andreas. The San Andreas itself is not a new development target for the region and has been productive for many years. What we are evaluating is the opportunity to apply horizontal development across our existing acreage, consistent with how we develop the other formations across our assets. Over the past year, our technical team has been assessing the potential of the San Andres across our acreage. That work has included extensive geological and reservoir analysis along with evaluating recent industry activity in the San Andres across and around our position. We believe that combination of internal technical work and encouraging industry results has given us conviction to begin allocating capital to the San Andreas with initial development planned for the second quarter of 2027 and initial production results later in the year. The San Andres potentially provides approximately 90 additional net development locations across our acreage. Importantly, these additional locations are within the acreage we already own, adding potential inventory without incremental acquisition cost. Our current plan includes six San Andres Wells during 2027, which should allow us to begin evaluating the opportunity through our own development results. Additionally, the infrastructure environment in New Mexico has materially improved. The Water Bridge Water Handling Agreement went into service in September, and the new Targa Gathering and High Pressure Trunk Line System was placed in service in October. Together, these projects provide additional water handling capacity and gas flow assurance to support increased development in our New Mexico acreage. That progress is important as we move into the next phase of our development plan. Over the past several years, we have significantly expanded our inventory position while investing in the infrastructure necessary to support a large development program. In 2026, we increased activity and the benefits of that development program became evident in our production results. As we enter 2027, we believe we are positioned to continue that progression. While we are not providing formal 2027 guidance today, I do want to provide an early preview of our plans for next year. We expect to add a second rig during the fourth quarter of 2026 and operate two rigs for a portion of the quarter, positioning us to carry that activity level into 2027. Based on prevailing commodity prices and market conditions, we plan to run two rig throughout 2027! As always, we will continue to monitor the environment and retain the flexibility to adjust any activity as conditions warrant. Our planned activity includes the development across both of our core assets. At Red Lake, the improved infrastructure backdrop allows us to increase development activity across the Paddock and Blind Bree while beginning initial development of the San Andreas. At Champions, we expect to continue developing the remaining high-quality inventory that and has continued to generate strong results. Based on this planned activity, we expect another year of meaningful production growth. While our 2027 planning process is still ongoing, our current outlook is for oil and total production growth of 30% to 40% year-over-year. We expect to provide formal 2027 guidance in March of 2027. We're excited about the progress we made this quarter, and more importantly, the position we have built heading into 2027. I want to thank our employees for their continued hard work and execution. We have asked a lot of the team this year as we have increased activity and grown the business and they have continued to deliver. I'll now turn the call over to John. Thank you, Bobby, and good morning. I'll cover our third quarter operational results, progress across Champions and Red Lake, and the work underway as we move through the fourth quarter and into 2027. As always, I'll begin with safety. Safe and reliable execution remains the foundation of how we operate, particularly as we manage a larger development program and growing infrastructure footprint. During the third quarter, we reported a total recordable incident rate of zero and delivered 95% safe days. During the 3rd quarter, We drilled 13 gross or 8.6 net operated wells, completed 9 gross or 7.9 net wells, and turned 12 gross or 11.9 wells to sales. All the wells turned to sales during the quarter were in Texas. Year to date, we've drilled 54 gross operated wells, completed 40, and turned 35 to sales. We ended the quarter with 25 gross or 17.3 net drilled uncompleted wells. Approximately 85% of those ducts are in New Mexico, and we currently plan to complete that inventory over the next two quarters. Production results demonstrate the impact of all that activity. Oil production increased 20% quarter-over-quarter to 25.4 thousand barrels per day, while total production increased 23% to 42,000 barrels of oil equivalent per day. At Champions, oil production increased 17 percent sequentially to 18.5 thousand barrels per day, primarily reflecting the contribution of new wells brought online during the year. At Red Lake, oil produced increased 30 percent to 6.9 thousand barrels per day despite no new wells being turned to sales during the first nine months of the year The increase at Red Lake primarily reflects the return to more normal operations following the third-party midstream constraints we experienced during the second quarter. Last quarter, we said the June exit rate provided a better indication of our second half starting point than the second-quarter average. Our results support that view, as shut-in volumes returned and Texas wells completed earlier in the year contributed to production. The growth reflected multiple factors, including restored production, new Texas wells, and continued optimization of the existing asset base. Our Yoakum County asset remained the primary driver of development and production growth during the quarter. We turned 12 gross wells to sales in Texas, compared to seven gross wells completed during the period, as activity completed earlier in the year converted to production. That is an important part of the story. During the first half of the year, we invested in drilling, completions, facilities, and takeaway capacity to support a higher pace of development. In the third quarter, much of that work began translating into production. Champion's high working interest, established operating footprint, and more mature infrastructure continue to give us flexibility in how we sequence activity and respond to changing conditions. During the quarter, we also selected a number of Champion's wells for targeted chemical treatments. Those treatments had limited impact on third quarter volumes because of their timing, but our current forecast reflects approximately 15% higher fourth quarter production from the treated wells. This is another example of using lower cost optimization work to create incremental production and improve recovery from the existing asset base. At Red Lake, our focus during the quarter was on preparing the asset for increased completion and development activity. Importantly, oil production also continued to recover from the second quarter midstream constraints, increasing approximately 30% sequentially despite no new wells being turned to sales. During the quarter, we drilled eight gross New Mexico wells and completed two, but did not turn any new Red Lake wells to sales, that sequencing was intentional. As discussed last quarter, We've been coordinating completion activity with the availability of gas, water, power, and supporting field infrastructure. We made important progress on those infrastructure needs during the quarter and shortly thereafter. Waterbridge began supporting the development program in mid-September, and Targa began taking volumes on its new high-pressure line in October. With that additional takeaway capacity now available, we have secured a full-time frat crew and begun working through the New Mexico duck inventory while continuing to drill new wells. This increased completion activity will contribute to higher capital spending in the fourth quarter, with the production impact expected to begin toward the end of the quarter and continue into the first quarter of 2027. On water, the water bridge arrangement provides additional disposal capacity to support increased development. While third-party disposal carries a higher cost than our own system, we believe that incremental cost is a favorable tradeoff for the additional capacity and development flexibility it provides. We're also continuing to invest in company-operated water infrastructure, including additional saltwater disposal capacity, gathering lines, pumping capacity, automation, and related field facilities. Our objective is to utilize a combination of company- operated and third-party capacity to provide a flexible and reliable water system as development activity and produced water volumes increase at Red Lake. Looking ahead, our priorities remain straightforward. First, we will continue to operate safely and maintain the discipline required to manage a higher level of activity. In Texas, we continue converting the investments already made into production while addressing the oil, gas, and water infrastructure needed to support the current development pace. In New Mexico, we will begin to see the impact of the duct inventory as gas and water takeaway systems are now operationally ready. The sequencing is deliberate. We began completing our ducts immediately after Targa and Waterbridge commenced initial operations. That production impact will begin to be seen toward the end of Q4 2026 and into Q1 2027 as those wells are turned to sales. Finally, we are preparing for a larger 2027 operating program. The third quarter demonstrated what the business can deliver as operational constraints ease and prior capital begins converting into production. Moving forward, we're preparing for a two-rig development program and further infrastructure build-outs that will accommodate meaningful Red Lake growth. Our focus from here is execution, maintaining safe operations, bringing infrastructure online, converting ducts efficiently, and ensuring that capital translates into production and cashflow as quickly as practical. I'll now turn the call to Philip. Thank you, John. Cashflow from operations was $111 million, 75% higher than in the second quarter, or $222 million year-to-date, 50% higher than the same nine-month period in 2025. Third quarter, accrual capex decreased 39%, quarter over quarter to $53 million, mostly in tandem with the decline in DNC activity. Cash capex was $66 million as payments for second quarter's higher activity flowed through the third quarter. Year to date, accrual capex is $187 million and cash capex is $165 million. We paid $8.4 million in dividends during the quarter and we had zero buybacks. With excess cash, we reduced debt by $28 million to $245 million, Quarter-end total shares outstanding, including unvested shares, were $22.2 million. Year-over-year, debt is down by 35%, and shares outstanding have increased by less than 1%. Subsequent quarter-end, we drew on a revolver to retire our 10.5% senior notes at par for zero net change in debt balance. We estimate approximately $5 million in annual interest expense savings. Last week, we completed an amendment to our credit facility, upsizing the borrowing base and elected commitments to $450 million, allowing for $205 million of undrawn liquidity. We also extended the maturity to October 2030. Stepping back, we have demonstrated that growth and financial discipline are not mutually exclusive. Over a three-year period, we have increased oil production by more than 80%, while reducing total debt by nearly 40%, and limiting shared account growth to 10%. We're scaling the business while improving the balance sheet and managing dilution. Now a few comments on forward guidance and capital allocation. Bobby and John described the additional activity for the fourth quarter. That drives an increase in capex for the full year relative to previous guidance. We forecast a small amount of incremental production volumes in the fourth quarter, while added volume should materialize more meaningfully in the first and second quarters of 2027. Additionally, while annual results remain an important measure of performance, given the pace and timing of our growth, we're increasingly focused on the progression of the business from quarter to quarter. In periods where capital investment precedes the associated production, calendar year comparisons do not fully capture that growth trajectory. We've added several new charts on pages 11 and 12 of our investor presentation that shows this actual and forecasted progression on a rolling quarterly basis, and we think they tell a compelling story. As we think about capital allocation, we're focused on creating long-term value on a per-share basis. We have a deep inventory of attractive development opportunities, and under current market conditions, we believe investing in that inventory is our most compelling use of capital. At the same time, we'll retain flexibility with the pace of investment. As Bobby mentioned, we will evaluate against commodity prices, the broader market and economic backdrop, full cycle project returns, and our balance sheet goals. Our objective is to fund the development program from internally generated cash flow while maintaining a strong balance sheet. And importantly, that flexibility does not necessarily mean giving up the growth already underway. A significant amount of capital has already been invested ahead of the associated production response. Even in a meaningfully lower commodity price environment, we believe we could materially reduce capex while continuing to grow production into the middle of next year, and then moderate activity as needed to maintain a more balanced cash profile. Thank you all for your attention today and for your interest in our company. Operator, you may now turn it over for questions. We will now begin the question and answer session. Please limit yourself to one question and one follow-up. If you would like to ask a question, please press star 1 to raise your hand. To withdraw your question, press star 1 again. We ask that you pick up your handset when asking a question to allow for optimum sound quality and if you're muted locally, please remember to unmute your device. Please stand by while we compile the Q&A roster. Your first question comes from the line of Derek Whitfield with Texas Capital Bank. Your line is open. Please go ahead. Thanks. And good morning, and thanks for taking my questions. And also, thanks for the early outlook on 2027. With respect to your outlook, there's seemingly a disconnect this morning in the value of your growth trajectory in both the $70 and $90 scenario. As it relates to your CapEx assumption, could you speak to what you've embedded in the estimates from an activity and inflation perspective, and if you've embedded any efficiency gains in those projections. moment please we are experiencing technical difficulties hold while i try while we work to to fix that okay i'm gonna keep going here uh yeah so we've got the second rig we've got that contracted with uh some good flexibility only about a quarter of the year is contracted so that's a small amount out of the total um frac crews should be coming in as well but as we think about the different prices uh we've shown you you know an illustrative range here of 70 to 90. currently we're above 90 in the market right about there um we show very material growth there uh at that level that that corresponds to what bobby was describing as that kind of 30 to 40 year-over-year growth you can see it on a sequential quarterly basis and then down at 70 we just show an illustrative range of what we think we could do that grows pretty meaningfully through the second quarter of next year and then slows down moderately uh both of those are just illustrative we still got to finish that off uh with our board and then like like bobby said we'll come back in march and give you uh more more confirmed guidance very quickly on the efficiencies um we we're really going to be in conservative here on how we're modeling that uh we hope to realize some but haven't uh haven't relied on it too much and then inflation uh we're assuming a modest amount of inflation some of which we're seeing in the tangibles maybe 10 or so uh and i i think some of that's obvious you've heard it from others derek uh the casing the diesel some of the chemicals and such anything else i'm missing john yeah no i think you've hit it right on the head uh 10 10 built into our cost forecast but really we believe we're offsetting any kind of cost increase from diesel and casing um with various things were other synergies that we're doing. So we think that, you know, we aren't, we are actually realizing a net effect of zero for inflation. And as you mentioned, we're only contracted for about 25% of the wells we plan on drilling next year, and only about 10% ofthe completions that will, you know, be bound to do. So we have a tremendous amount of flexibility to have to, you know, deal with various market conditions or any kind of results we might see. So great amount of flexibility. Great. So definitely tremendous flexibility, very conservative assumptions. Maybe shifting over to the stand injuries with my follow-up, clearly an important pinnacle for you guys as you think about the resource expansion opportunity given the growth outlook. I guess based on your extensive review of the subsurface and industry results, could you speak to how the interval compares to the Blundberry and PADC intervals and what you're expecting from an EUR and cost perspective? Yeah, so we view this as just an additional interval within a co-developed multiple bench resource so uh the paddock and blindberry are still going to be the foundation of the development um the san andreas is just slightly shallower but again allows us that benefit of using existing infrastructure that we already control and doing this on acreage that we already have um so it's a big benefit you know we were going to start full field development we were a year ago or so building that in the infrastructure so that we would be ready and we knew this was already a target for vertical wells and just decided that it would be so much easier to co-develop it with the yeso and so that's the path our our technical team started studying and then got to the point where we feel comfortable adding these uh uh adding these potential locations uh i don't i don' believe we're ready yet to talk about EURs but again we feel comfortable with our experience and champions with the San Andreas this is a this is 80 miles away and uh same zone but uh there's always still differences in rock quality and things we want to investigate with our own program uh but we're uh we're excited about what we've seen so far from public data and um you know our view of industry activity within our own fairway so uh feel feel really really good about it fair enough it seems very encouraging thanks for your out. Your next question comes from the line of Neil Dingman with William Blair. Your line is open. Please go ahead. Morning, Bobby and team. And Bobby, I just want to say, yeah, that I think this plan, ops plan of yours makes total sense here. My question is around the plan as well as sort of DERA-CAST. And could you remind me, you know, with this two rig consistent plan, on how many wells we're talking about you might be able to knock out in I don't know a year or so and I think you mentioned this earlier but I'm assuming now you believe you'll have more than ample takeaway for this type of growth yeah we will let me get the number that we're uh we're looking at right now on a net basis it's about 90 90 walls okay but but you're right the takeaway allows us to uh to get this uh program underway so we're pretty excited about it and and and if i could ask one more on that one could will the two rigs remain in kind of the same focused areas or how much how much will you move those two rigς around yeah in general we'll have one rig in champions and then one rig moving over to new mexico it'll probably move over there about in oh late late first quarter i would say um we want to really focus on completing our ducks in new mexico uh first that will allow us to increase production there and start start filling our infrastructure as we uh get a little bit ahead in champions and then move back over and start handling some of these uh large multi-well pads in new mexico got it and then second if i could just on the expansion initiatives across the red lake acid could you talk about i really think there's some interesting upside there because one of you all talk about just up you know the various upside are you talking about just the one incremental formation or you know how much inventory upside could we be referring to um from an inventory standpoint you know we're gonna we're going to be drilling the paddock blindberry and as we as we get it permitted the uh san andres um we have you know initially put 90 net wells out there for the san andreas we have not evaluated all of the sanandrus yet So we believe there's potentially additional upside there, as well as other formations. But as far as our 2027 plan goes, we'll be doing all three layers, you know, again, with some pretty decent sized pads. And, you Know, as you've noticed, our production is occasionally comes on in waves. But when you do some of these larger pads of six, seven, eight wells, you know, again, you have to wait until all those wells get fracked, all those Wells get drilled out before you actually bring on that pad. And so, especially in New Mexico, I think you're going to see, again, it be coming on in waves. Again, we're already starting completion of ducks. We just finished fracking about our first 10 of the 24 New Mexico ducks. And again, we'll start soon drilling those out. And then there's usually a bit of a flowback period before you get stronger oil and gas. And so that's why, even though we've already started, you won't see any decent impact from those particular wells until early January. Perfect. Thank you all. your next question comes from the line of jeff robertson with water tower research your line is open please go ahead thank you good morning john on this and andrews how much do you still need to understand with respect to how best to complete horizontal wells in the zone in red like yeah i i think we've learned quite a bit in in champions about the san andreas in general um you know but there there's still differences in reservoir character uh the particular depletion history you know in in new mexico may be slightly different than uh than texas fluid properties So we'll have to zoom in on our completions and learn from these wells. Obviously, we will use that champion's experience to start with, but then we'll be tweaking as we go to handle the various technical differences and what we see of how they perform. do you think that it's the best approach will be to co-develop this in andrews with the blindberry and paddock on pads oh absolutely um you know we want to it's it's even though they are separated um geologically with a barrier in between we just want to make sure that all of our frac energy is is contained in the san andreas as we complete it as well as our other intervals so it makes so much more sense to co-develop those you'll get the best frac job in each interval and if you think about rig moves costing you know like a hundred hundred fifty thousand per rig move. Every time we stay on one pad and do avoid a rig move, you know, we're doing zipper fracking, again, for that best frack possible. It just really starts adding up to a lot of money besides just the technical applications. Thank you. as a reminder if you would like to ask a question please press star one on your telephone keypad now to raise your hand your next question comes from the line of nicholas pope with roth capital partners your line is open please go ahead good morning everyone good morning good morning. Curious. It took all the fun geology questions. I'm curious with the startup of the gathering of midstream assets and this contract with WaterBridge for water handling, what that means for the trajectory for operating and gathering costs going forward over the next year as you kind of expand and grow production like on i mean is it gonna be a meaningful difference with current um kind of unit rates on on production no i don't i don t think so on the uh on the gas side it should be similar uh on water you know there's there certainly is a an increased cost when at going to water bridge again we we view that as a favorable trade-off to uh even though that costs a little bit more money you know it allows us to develop at our own pace um not to worry about that we can we can don't have to sequence things quite as much as we used to uh because we had that capacity now but we also work hard to give water bridge the minimum that we have to and fully use our own saltwater disposal system uh just because uh you know it's uh uh substantially less expensive uh from those investments that we've made in the past so we look at that as really kind of a combined rate in our own head of fully utilizing our own and then giving the excess to Waterbridge. I'll just follow up back on the target line. We've always said this is primarily about flow assurance, and so that's what's manifesting or allowing this increase in activity for John's operations here. At the same time, we do hope to get better NGL yields, so this will be much newer equipment and plants it'll be running through. We think that ultimately shows up in better NGL yield and those command the better value there. Some of it can be slightly higher fee, but we hope to offset that. This quarter, just for the avoidance of doubt, this quarter we had some higher gas realizations that was not due to this specific infrastructure, but rather some of the changes you saw on the downstream residue gas line egress that improved WAHA there and allowed us to absorb the fees with the gas and the NGL both. Gas prices are volatile, as you know, they're looking decent at the moment, weaker again next summer, and that probably will continue to be volatile. Yeah, I appreciate that. could dig a little bit more into the uh the new inventory and what y'all are looking at with san andres um the 90 wells uh they are looking that that they're adding to you know potential inventory is i guess the the cri what are the criteria like and how y' all are defining you know what what you're comfortable adding into inventory is it just proximity to to near-term drilling and plants that you have on the deeper formations. I'm just more curious, I guess, what, how y'all judged the criteria to kind of tentatively add that into inventory. Yeah, so let me preface that with just saying, you know, look, our team did a significant amount of technical work over the past year. Everything from geologic reservoir analysis, Again, looking at the legacy vertical production depletion, looking at recent horizontal activity. So there was a lot of work put into that, especially oil in place mapping was a significant, I'd say the oil in-place mapping and depletions were kind of significant things that helped us figure out where to attack first, looking at some of your best opportunities first, And then you're exactly right, proximity to, you know, known resource, starting with a conservative spacing of four wells per section. You know, we think that's the key is basically starting with close proximity and knowing what your technical information is leading you towards. and then let our own performance on our own operated wells kind of help dictate how and where we accelerate the program to. Got it. That's very helpful. Fun stuff. Appreciate the time. Thank you. Your next question comes from the line of Jeff Robertson with Water Tower Research. Your line is open. Please go ahead. Thank you, Jeff. A question on the production profile. As Red Lake becomes a bigger part of Riley's mix, will that have an impact on the production mix between oil, gas, and NGLs? Yeah, it might be a little bit gassier. I think at the moment, Red Lake is gassyer as a function of it being older. Sorry, a larger amount of the mix is some of the old legacy vertical wells. New wells are going to be oilier, and so that generally will make that field itself oilier. As for the overall corporate mix, it might get slightly oilier there, but not a material amount, Jeff. This is still an oily field, oil-driven play, and economics will continue to be well-driven with oil revenue. philip on oil revenue can you talk a little bit about how you're thinking about with about hedging volumes i know the hedged volumes based on the preview outlook you have for 2027 goes down pretty significantly from what has been hedged in 2026. you know with hedging we begin with the lens of risk management and that is a function of what our capital structure looks like and what our capital obligations are if we look back 18 months ago we were sitting here telling you how we were buying an acquisition with 100 percent debt tightening our belt to get that done and at the same time we had this large nine-figure gas midstream project that we were developing this was prior to selling that to targa so it was a different set of capital obligations and so we had more more to hedge and to manage the risk. At this point, we have a very healthy balance sheet, and that really drives some of our thinking. We try to be careful not to speculate. I think we're quite hedged at the moment. For the coming remaining months of the year, we're a little under 60 percent. First quarter, it's looking, you know, plus or minus 50 percent of total volumes there. And then, yes, does decline through the year, as you note, pretty materially there. When you compare us to others, I think we're very much in line. We're going to be more hedged further out on 12 to 18 months versus the large caps versus small caps, I think, were very similar. But what I'd end with here is that it continues to be a very volatile world. Look at the last 24 hours. The front month is still, we still have quite a bit of backwardation over a three to five year period. So we wanna be careful not to lock in too much. You can't hedge service costs. Typically you can't head your LOE and your capital costs. And so we wanna mindful to be ultimately price takers on our revenue and match that with our costs capital. Thank you. We've reached the end of the Q&A session. This concludes today's call. Thank you for attending. You may now disconnect.