Riley Exploration Permian, Inc.REPXNYSE
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Operator: 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.
Philip Riley: 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.
Bobby Riley: 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.
John Suter: 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.
Philip Riley: 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: [Operator Instructions] Our first question will come from the line of Derrick Whitfield with Texas Capital.
Derrick Whitfield: 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.
Philip Riley: 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?
John Suter: 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.
Derrick Whitfield: 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.
John Suter: 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.
Derrick Whitfield: 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.
John Suter: 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.
Operator: Our next question will come from the line of Neal Dingmann with William Blair.
Neal Dingmann: 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.
John Suter: 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.
Bobby Riley: 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.
Neal Dingmann: 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.
Philip Riley: 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.
Neal Dingmann: Philip, again, fantastic deal also on the midstream project.
Operator: [Operator Instructions] Our next question will come from the line of Nicholas Pope with Roth Capital.
Nicholas Pope: 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?
John Suter: 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.
Nicholas Pope: 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?
John Suter: 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.
Nicholas Pope: 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.
Bobby Riley: 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.
Operator: Our next question comes from the line of Noel Parks with Tuohy Brothers.
Noel Parks: 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.
Philip Riley: 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.
John Suter: 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.
Noel Parks: 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.
John Suter: 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.
Operator: Our next question comes from the line of Jeff Robertson with Water Tower Research.
Jeffrey Robertson: 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?
Bobby Riley: 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.
Jeffrey Robertson: 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?
Philip Riley: 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.
Bobby Riley: 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.
Jeffrey Robertson: 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.
John Suter: 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.
Philip Riley: 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?
John Suter: Right. And we do have a lot of undedicated acreage at this point. So we still have flexibility for future options as well.
Jeffrey Robertson: 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.
Philip Riley: 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.
Bobby Riley: 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.
John Suter: Yes. And that spacing you were mentioning is 320.
Jeffrey Robertson: Yes. Okay. Those would be locations added on existing acreage. So there's really no incremental cost.
Bobby Riley: No incremental cost in the acreage, that's correct.
Operator: This concludes the question-and-answer session and our call today. Thank you all for joining. You may now disconnect.