Riley Exploration Permian, Inc.

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. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star then the number one on your telephone keypad. To withdraw your question, press star 1 again. I would now like to turn the conference over to Philip Riley, Chief Financial Officer. Please go ahead.

Good morning. Welcome to our conference call covering our fourth quarter 2025 and full year 2025 results. I'm Philip Riley, CFO. Joining me today are Bobby Riley, Chairman and CEO, and John Suter, COO. Yesterday, we published a variety of materials which can be found on our website under the Investors section. These materials in today's conference call contain certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. We'll also reference certain non-GAAP measures. The reconciliations to the appropriate GAAP measures can be found in our supplemental disclosure on our website. I'll now turn the call over to Bobby.

Thank you, Philip. 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 seven to eight 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 billion 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 Target 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 laid 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 results of Riley Permian's multi-year 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 an 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 Riley, our CFO, who will review financial performance. Thank you, Bobby, and good morning. I'll briefly cover fourth quarter and full year results, followed by 2026 development plans. Beginning with the fourth quarter, our development activity was focused in Texas. Activity levels matched 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 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 three new wells turned to sales during the fourth quarter. Comparing the fourth quarter of 2025 to 2024, 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 zero 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 mid-year 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 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%, or over 2,500 barrels 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 worldwide cleanouts, artificial lift optimization, and return to production operations. As for drilling and completion operations, we're down 25% in cost for lateral foot and red lake year over year. Similar results were achieved in Texas. with a 15% cost reduction for lateral foot in 2025. Both achievements were driven primarily by a focus on pad drilling, an increase in time spent drilling, and completion 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 one-rig program. In actuality, we have two rigs running for approximately three months through May, back down to one rig for the summer, down to zero potentially for the fall, before picking one up again later in the year. We picked up a 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. two-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 ducks to draw from, as I referenced during my commentary on fourth quarter activity. New wells turned to sales will focus in Texas during the first half of the year and transition to New Mexico for the second half. This is predicated on the Mexico gas infrastructure being completed and ready by that time, as Bobby described. Additionally, we've been working with partners to secure sufficient water disposal for this development plan. This will increase operating expenses, which we see impacted later in the year, while we're also tackling initiatives elsewhere to offset this increase. Philip, I'll now turn the call back to you.

Thank you, John. We'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 three 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 are 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 non-recurring items such as the $72 million gain from the midstream sale and from $20 million of higher hedging gains, which were mostly non-cash, 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. That's $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 was ultimately reimbursed with the 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 do 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 1.0 times on an as-reported EBITDAX basis or 0.9 times on a pro forma basis, including first half 2025 Silverback EBITDAX. On a full-year basis, adjusted EBITDAX and upstream free cash flow decreased by only 8% year-over-year, despite 15% lower oil prices. Total free cash flow is 31% lower year-over-year, driven by lower prices and higher midstream spend, which, of course, is non-occurring. 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 their land ground gain 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 two-thirds 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 two-thirds 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 two-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 we'll protect the dividend and lower price environment. We entered 2026 well hedged, partially on account of the midstream capital commitment we were carrying 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 2nd, 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 callers preserving upside participation. Thank you all for your support and attention. Operator, you may now turn it over for questions.

We will now begin the question and answer session. To ask a question, simply press star followed by the number one on your telephone keypad. Our first question will come from the line of Berwick-Woodfield with Texas Capitol. Please go ahead.

Good morning all and 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 ramps in 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 2027, would you expect it to improve in 2027 as you optimize D&C designs and get more reps than Eddie, and as you back out some of the duck impacts in 2026?

Yes, sure, Derek. 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 one 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, yeah, depending on how you define capital efficiency, we've got a few different metrics, but yeah, 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 then. 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, you know, frankly, kind of flattish CapEx is what we're showing for now. 2027 is a long way away, 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 shutdown?

Yeah, sure. Yeah, 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, you know, 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 several of us mentioned, there will be heavy champions activity, in the first half of the year. And then we're 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, you know, that's on schedule to happen. And so we're really excited about that. We'll start ramping up our completion. Still won't get the full impact of it in in Q4 because a lot of things are being completed then and, you know, we'll have to do water a little bit. But all the better for 27 as we should be able to start drilling, you know, more efficiently in New Mexico and completing those wells as we go. So it should be more efficient without having to wait on some water infrastructure, and some gas takeaway like we are this year.

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

Sure. Well, again, we've been mostly in champions. We're trying to do zipper fracks on pad drilling, zipper fracks on everything we do. We kind of think we've 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. So that's a big change over time, you know, goes against what we, you know, 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 4070, which is, you know, 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 it reduces our water volume and, of course, less pump time, which is a cost benefit. In New Mexico, there is upside there that we have tested a little bit. We plan to test more in 2026. The paddock layer of the blindberry is very similar to the St. Andrews over in Texas, and we would like to test more cross-link facts 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 a half million dollars plus per well. So we're excited to do some more testing there. Again, once we have that pipeline, we'll have the freedom to do a little bit larger scale drilling.

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

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

Perfect. Great update, guys. I'll turn it back to the operator.

Our next question will come from the line of Neil Dingman with William Blair. Please go ahead.

Good morning, guys. Great update. Phillip, maybe a question for you or Viber, John, just, you know, again, sticking with that slide, Tim. I've always loved the flexibility. Again, it certainly seems like, you know, in past years, what is it, has there been one rig that you've needed to have, you know, very material production growth? And I'm just wondering, you know, given now today, we're almost now back to $80 oil, you know, how flexible is this plan? And, you know, I know a lot of large companies always 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, You know, would you think about trying to, you know, capture this oil upside and even potentially grow quicker than, you know, just maybe talk about the flexibility of the plan, I guess, is the best way to ask him.

Yeah, I might defer some of that to Bobby for, you know, for a longer-term view of that, of increasing. But certainly, you know, we're talking about drilling that, you know, 45 to low 50s gross wells, The beauty of our wells being so shallow that compared to, you know, the Delaware is that we can knock a well out, you know, from spud to TD, you know, maybe four or five 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. one one rig can effectively drill um you know let's just say upper 40s to low 50s wells per year if you're able to not do you know a lot of regional moving um you know so it would not take much uh in deployment you know to be able to really drill quite a few wells so we have a capability and you know I may steer that back to Bobby to see what he thinks about drilling at a higher oil price. Thank you. Thank you, Neil, 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 DNC capital spend that really we're looking into 27 and beyond today. and how that is going to affect this company in any price environment, whether it be 55 or 85. We have the ability with the flexibility that Sean 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, too immature to really say what we would do at this point.

That makes sense, Bobby, and a lot of the flexibility – Second question, Bill, if you know, I can't help but ask on the powers, obviously, as far as I am on that. I know looking at slide 16, you guys talked about, I think, knowing on the second project, it's in the final stage. Could you talk, maybe just update on that, where that second project sits? And, you know, have you considered, you know, even adding more power beyond project number two? Because, again, obviously, you know, I'm a fan of this. And, again, I think as is this. The market would love just to hear any more plans beyond Project D. Sure.

Thanks. Yeah, 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 four sites, and the first of the four sites is in the final stages of commissioning, With ERCOT, that has a kind of four-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 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. 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. You know, ultimately, this is 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. They also have challenges with in-basin gas realizations. As for doing more, man, you know, Look how much has changed with power in the last two years, right, since 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. You know, gigawatt plants and data centers are massive operations, incredibly capital intense. You've 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, who 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.

Thanks, Phyllis. And, again, fantastic deal also on the Midstream project.

Thank you.

Our next question will come from the line of Nicholas Pope with Roth Capital. Please go ahead.

morning everyone morning morning um there was a there was some comments made about the new mexico operations that um i guess in the fourth quarter maybe even earlier in the third quarter you know when the compressor system came online kind of helped you know boost production um on top of artificial lifts uh you know just that whole work on the wells that have really

kind of yield some 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, you know, production level optimization right now, and maybe is there, do you all think you're fairly kind of through kind of integration of all those assets, or maybe there's more of that kind of quick hit low-hanging fruit type production work that you got going in New Mexico? Yeah, I would say related to the fourth quarter, some of the, there was a couple of early pads that we 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 the Red Lake asset we originally had. We have worked on a lot of integration there. We've combined our workforces, you know, got down to one 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 over performance, 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. 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 six months of Silverback was fantastic, kind of keeping it way flatter than we thought we would, and it's from the strong work over performance. 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 doesn't seem like there's a big uptick in LOE in the fourth quarter despite kind of the positive numbers. So I'm just curious, like, is that still ongoing? Is there still pretty fertile ground there to optimize? Yeah, it is. There's certainly quite a few wells. I can't remember how many horizontals they had, maybe 30-ish, if I remember right, and then a lot of verticals. But, again, we're just prioritizing, seeing what's the most effective way to start, and then, yeah, 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, you know, 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, you know, the large number of upside-type things there are here.

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

No, it's a very, very, very small amount. That was a legacy asset that we brought in, you know, I think prior to us, if it's one public, I don't know what the number was. A few hundred barrels. Yeah, a couple hundred barrels. That's it. All right, that's all I got. I appreciate the time, guys. Thank you.

Our next question comes from the line of Noel Parks with Tubi Brothers. Please go ahead.

Hi, good morning. Good morning. 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 is there anything about the balance in the costs incurred between what shows up as the acquisition side versus the development side? Because the development capex is sequentially lower year over year by a good bit, of course. And just in doing my calculations, it just looked like the one-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, you know, bringing new areas onto the books and I'm sure reallocating CAPEX with the SEC five-year rule and so forth. So any insight on that would be helpful.

Okay, no, I'll take a stab and follow up with you if you need to. Sure. 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 John described. We had lower activity in 25, you know, go back to April, May, Liberation Day, prices fall. At the same time, we capture that acquisition and we try to preserve capital for that. had a little bit of competition for the allocation given the midstream. So we worked through the year like that, were able to grow organically with modest activity like he described, 16.3 net wells put online. So I think a lot of it's that combined with the cost savings on DMC. 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 to develop 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, you know, just service announcement for everybody, we aim to take a pretty conservative approach. 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 and the five-year rule, as you mentioned, we just find it's, you know, easier to book as you go at the kind of minimum. So we focus on pre-developed probably more so than total proof.

Yeah, I think that's right, Phillip. Just with our relatively conservative pace, you know, 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, you know, 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. You know, we do do pad drilling, and so that hurts you from being able to go out and drill six different areas instead of six wells on the same pad. You can certainly put more puds if you do that. But I would agree with Phillip. We've taken a pretty conservative stance here, but we have a a lot of optionality in the future to improve that.

Great. Thanks. That does fill in a couple 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 you know, maintenance, maintenance tasks, work overs, making well board clean ups 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, you know, folks who really were coming from more of a private equity sort of financing background as opposed to, you know, being sort of just your typical operators. As you look around the other vintages of, you know, entries into the base and into conventional plays that various parties have done over the last, you know, five plus years or so, Do you anticipate similarly, I don't know if I called it 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 a deal something like Silverback is something that maybe over the next few years you can replicate easily?

Yeah, that's a, you know, 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. You know, 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, you know, we bought silver back. for the most part, for all of the drilling opportunity. You know, it's a ton of acreage right along trends in the yeso clay. That's why we bought it. All of this other stuff with production optimization is just a bonus in my book.

Great. Thanks a lot.

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

Thank you. 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?

Thanks for the question, Jeff. Basically, it's just another tool in our tool chain. to where we looked for being opportunistic. If we feel like the share price, which we do, is undervalued, it may be for us 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, you know, that may not lend to buyback at that particular time. But the fact that we're flexible and can spend our money either in stock buyback or development, you know, that's where we want to be. You see from the comments and from the files, I think we average 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.

Thank you. John, in your comments, I think you said – or maybe, Phillip, you said you replaced two-thirds 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 five 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 26th program?

I will attempt to answer that. Yeah. So the locations, I'd say they fall in kind of the middle of the 2 to 3X DROI. 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 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 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.

Now, let me add a little bit to that. We're focusing this year with our land group where we kind of restructured it to one of our key focuses is going to be what we call the ground game, which is this is not going out and buying 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 Yocum asset 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 one of our big focuses this year is going to be what we call the ground game and executing that and replacing our drilling inventory at least 100% with bolt-offs.

Thank you. And Philip, you all saw or 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 costs? Will it just improve efficiencies in the Red Lake area? How do you characterize the benefit of that?

Yeah, this is John. It's going to increase our cost, but what it does is allows for full-scale development the rest of the way for this field. So it's, you know, 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 a It's just like the target is for gas. It's to allow full field development without having to worry if there's any capacity somewhere.

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

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

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

Yeah, so we talk about it approximately 27 times a day and then think about it through the night. You know, we've been through Five years of volatility, right? We're trying to position ourselves and protect the program ahead. You know, 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, you know, absent liquidating some of those, we have those on the book. And I mentioned this in our prepared remarks. We also entered the year with everybody calling for a surplus and, you know, $50 or $55 WTI. So we're happy with where we are. You know, we'll 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, two-thirds of the hedges this year are in the form of swaps. With the balance and collars, the collars kind of have a range of weighted average. I call it 58 to 72. And so we feel good about that. There's plenty of room in there to make some margin. We, you know, 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 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. As I was 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.

Thank you. Jeff, this is Bobby. Let me follow up just to give you a little bit more color on your question on 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 micro seismic, 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 five wells, three in one bench and two in another bench. But we're kind of going to where we're going to add a whole other bench in the San Andres and some of our acreage and then modifying possibly by adding a well or two 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 do know there will be an increase. I don't know just how impactful it will be, but it will move a meter there. Yeah, and that space that you were mentioning is for 320. Yeah, okay.

Those would be locations added on existing acreage so there's really no increment of costs.

No incremental costs in the acreage. That's correct.

Thank you.

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