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Operator: Good day, and welcome to Riley Exploration Permian First Quarter 2026 Earnings Conference Call. [Operator Instructions] Please note that this conference is being recorded. It is now my pleasure to introduce your host, Philip Riley, our Chief Financial Officer. Sir, you may begin.

Philip Riley: Good morning. Welcome to our conference call covering our first quarter 2026 results. I’m Philip Riley, CFO. Joining me today are Bobby Riley, Chairman and CEO; and John Suter, COO. Yesterday, we published a variety of materials, which can be found on our website under the Investors section. These materials 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 turn the call over to Bobby.

Bobby Riley: Thank you, Philip. In March, we announced that Riley Permian would accelerate growth in 2026, which was a natural result from our multiyear positioning, including deliberate inventory expansion and infrastructure readiness. Our 2026 development plan was designed when the WTI spot price and 1-year forward price were in the $60 range, and we saw meaningful value creation potential at those price levels. Since then, the oil supply picture and price outlook have changed completely, we have increased confidence in achieving our planned targets and the corresponding value creation potential has increased significantly. Our first quarter results provide an initial round of momentum for the year ahead. We executed well, delivering production exceeding the high end of guidance while spending less than the low end of our capital guidance range.

With our excess capital, we reduced debt by $8 million and returned $12 million to shareholders through our dividend and share repurchases. Our first quarter activity levels increased materially over fourth quarter 2025 levels and second quarter activity will surpass first quarter, setting up for an accelerated growth. We forecast production growth continuing for each quarter through the year, culminating with full year growth of 30% at our new midpoint guidance levels. As we look further out to next year, we see the potential to grow production 10% year-over-year with only a 5% increase in CapEx, at least as one scenario being considered. We believe this could be achieved given the wave of second half 2026 volumes being generated. We have confidence in achieving this growth through accelerated development of both of our assets.

In New Mexico, Targa has progressed on the engineering and design for the high-pressure trunk line to their processing plants, which will begin construction upon final regulatory approval. The project timing remains on track with a scheduled commercial operations date in Q3. We will be ready from the upstream side with wells ready to turn in line immediately following the pipeline coming into surface, which gets us closer to achieving our first earn-out payment. All of this activity is exciting as is the potential to unlock value from this asset. In the meantime, and in parallel, we will continue to push forward with drilling and completions within our Texas assets, where we continue to drive efficiencies and where infrastructure is in a more mature stage of development.

Texas will comprise the bulk of our volume growth in 2026 and New Mexico should contribute more growth thereafter. Briefly on our ERCOT power project within our RPC joint venture, our first site, a 10-megawatt facility located in Ward County, Texas, is in the final commissioning stage with ERCOT. During the commissioning stage, we’ve been generating power into the real-time market and collecting a modest amount of revenue. We have a forecasted commercial operational date for later this month, after which we can begin regularly participating in the day-ahead markets. Our second site is fully constructed and is in the early commissioning stage. Our final 2 sites are scheduled for late summer. Over at our behind-the-meter project at Champions, we’re saving approximately $200,000 per month or more on avoided negative gas sales at recent prices.

Between these 2 power projects, our thesis remains intact here, and we see this as one small way to counter the weak regional gas pricing that we’re realizing on our upstream assets. As always in our capital allocation process, we plan for optionality. As the year progresses, we will monitor the macroeconomic backdrop and industry conditions, and we will maintain flexibility to speed up further or slow down should conditions deteriorate materially. Keep in mind, the original accelerated plan was contemplated at a $60 price. These strong financial and operational results, along with the opportunities on the power side as well as additional new opportunities we continue to evaluate on a product of our exceptional operational, planning and technical teams.

To our employees and our investors, we believe Riley Permian is well positioned for an exciting 2026 and beyond, supported by our high-quality asset base and strong financial position. I’ll now turn the call over to John Suter, our COO.

John Suter: Thank you, Bobby, and good morning. I’ll briefly cover our first quarter operational results and how activity progressed through the quarter, and then I’ll touch on how we’re positioned as we move through the balance of the year. Safety remains foundational at Riley Permian. To start the year, our operations reported a 0 total recordable incident rate, and we delivered 96% safe days. Turning to operations. Development activity ramped meaningfully in the first quarter and was concentrated primarily in Texas. On a net basis, we drilled 15.6 wells, started completions on 12.8 wells and turned 8 wells to sales. Importantly, we delivered this increased level of activity with strong capital discipline. Total capital spend was $47 million, which was below the guidance range, driven primarily by normal timing dynamics, including selective deferrals and infrastructure timing and a small amount of activity mix changes that reduced spend without impacting our plan.

From a production standpoint, net oil averaged 20.2 M barrels per day and total equivalent production averaged 35.6 MBOE per day, exceeding the high end of guidance. Volumes were essentially flat quarter-over-quarter as strong development well contributions offset normal base decline. Winter Storm Fern caused disruptions across the Permian among midstream providers and producers alike in late January and into early February. We, on the other hand, experienced minimal downtime with little to no impact on quarterly volumes. Within the quarter, development well performance was particularly strong. Initial oil volumes exceeded forecasts, and the outperformance was driven more by well productivity than simply timing. As we look ahead, we’ll continue executing the plan with a focus on safe, reliable operations and disciplined capital allocation.

In the second quarter, activity is expected to increase from the first quarter with 2 rigs running full time and 16 to 18 planned completions by quarter end, 30% more than in Q1. This level of completion activity will contribute to a production ramp that we will see later in Q2 and drive strong full year growth. Completions are expected to remain focused in Texas, while we work through gas takeaway sequencing in New Mexico, including the progress of the Targa gas pipeline project, which Bobby alluded to earlier. Looking into the back half of the year, our current plan contemplates releasing the New Mexico rig in the third quarter and continuing to drill in Texas with a return to New Mexico activity later in the year to align our completion cadence with infrastructure readiness and set up the broader New Mexico program.

Now let’s move on to operational performance in Q1. Lateral drilling performance continued its multiyear upward trajectory. A higher median lateral feet per day in combination with a tighter distribution demonstrates repeatable, scalable execution. Consistent use of multi-well pads and zipper fracs materially reduced downtime and per well cost while improving overall operational consistency. We drilled a record spud to TD well for a 1.5-mile Yoakum County San Andres well in Champions at 4.28 days and a separate spud to rig release record at 5.79 days. We also successfully executed drilling and completing 2 more 2-mile laterals, delivering the fastest drilled wells in the field at 1,456 lateral feet per day, validating the efficacy of longer reach designs.

Well costs as it relates to drilling and completions year-to-date have been relatively stable despite inflationary pressure on service prices, primarily driven by efficiency in our operations. Diesel costs have obviously come up substantially in the last couple of months, driving many service companies to adjust pricing accordingly. Our ability to drill faster and complete more efficiently has allowed us to mostly outpace this increase thus far. LOE has gone up slightly quarter-over-quarter in Q1 when compared to Q4 2025, in part due to some elective workovers that were deferred from Q4. Bigger picture, it should also be noted that despite being up quarter-over-quarter on an LOE per BOE basis, we’re still seeing a downward trend year-over-year with a 10% reduction in cost when compared with Q1 of 2025.

The elective work I previously mentioned was primarily in our Red Lake asset, where many of our older wells have found new life following mechanical interventions. These workovers have resulted in nearly 500 net barrels oil per day of relatively flat production with some recent wells continuing to increase in oil cut. This is some of the most capitally efficient dollars we spend with economic metrics comparable to new drilled wells in the area. We estimate that to date, we’ve only realized 30% of the possible uplift of these older wells and between the sizable inventory in our New Mexico asset and the combination of higher commodity pricing, the magnitude of unrealized production growth could be even greater. We’ve also mentioned in past calls, our expectation of chemical costs coming down in New Mexico as part of a change in program we implemented in January.

I’m happy to report that in just a few months, we’ve seen costs nearly cut in half on a per barrel basis compared to our 2025 monthly average spend. While we’re starting to see that creep back up due to an increase in petrochemicals costs across the board, we’re confident that the changes we’ve made will help minimize the effect going forward. Stepping back, the message is straightforward with several key takeaways. We’re executing safely and efficiently while scaling activity with discipline. We delivered strong first quarter volumes and capital performance. We’re seeing continued gains in drilling and completion execution that help offset service cost inflation. And finally, we’re prioritizing Texas where infrastructure is ready, while sequencing New Mexico activity around the Targa takeaway build-out to protect returns and preserve flexibility as we move through 2026.

I’ll now turn the call to Philip.

Philip Riley: Thank you, John. I’ll cover first quarter financial results and provide an updated company outlook. Unhedged revenue increased by $17 million, or 17% quarter-over-quarter, driven by 18% higher oil revenue and partially offset by weaker natural gas and NGL revenues. Gas and NGL revenues after fees were negative $11 million and reduced our total net revenue by 9%. Structural gas egress constraints, combined with seasonal midstream maintenance programs negatively affected gas pricing for producers across the Permian. Our revenue net of derivative settlements declined by $3 million, or 3% to $102 million, driven by gas and NGLs, as hedged oil revenue was flat. Operating cash flow was $47 million or $55 million before changes in working capital.

Analyzing quarter-over-quarter variances, this cycle may be less relevant given some unusual impacts in the fourth quarter 2025 related to the midstream gain and corresponding income tax impacts. Adjusted EBITDAX declined by $5 million, or 8% quarter-over-quarter to $61 million, driven by $3 million of lower gas and NGL hedge revenue, combined with $2 million of higher operating costs and production taxes. We’re reporting a net loss on a GAAP basis of $70 million, driven by $127 million loss on derivatives, 91% of which was unrealized. We entered the year materially hedged to protect the 2026 capital program. The bottom line net impact should reverse over time as the mark-to-market loss is offset by increased revenues from corresponding production over the same contract periods.

GAAP mark-to-market accounting can introduce significant period-to-period volatility that does not reflect underlying operating results or long-term cash-generating capacity. Most energy investors are familiar with these limitations and will evaluate performance accordingly. Our business continues to generate meaningful cash flow, which should increase materially in the coming quarters if oil prices remain elevated, as we’re only about 67% hedged for the balance of the year. Here’s one anecdote on the hedging to consider. We underwrote the acquisition of Silverback a year ago, when spot oil price was in the $60 range and the 12-month forward price was in the high 50s. We financed the acquisition using 100% debt with 0 dilutive equity. Many of the hedges we have today are a result of that financing.

Since then, in this new price environment, and assuming closer to a $70 long-term price, the value of that asset and undeveloped locations have increased materially, which is not reflected in our reported financials. For example, consider the value of an undeveloped location. Incorporating an oil price of $70 versus $60 increases the net present value at a 20% discount rate by 60% to over 100%, depending on the type of well. Moving on to our investments. First quarter 2026 total accrual-based CapEx was $47 million, while cash CapEx was $31 million, only 2/3 of the accrual amount, which is not unusual in a cycle when you’re increasing activity rapidly given the time lag of payables. We had several smaller acquisitions and divestiture deals for a net benefit of $5 million based on selling some small nonoperated assets.

With remaining cash, we invested $4 million in the Power JV, or $2.5 million net of a small distribution, paid $8.4 million of dividends, reduced debt by $8 million and bought back $4 million of stock. Now let’s discuss our outlook. We have a big second quarter of development activity, and we’re guiding to $80 million of accrual CapEx. For the full year, we’re increasing our full year guidance range by $10 million, representing a 5% increase at the midpoint of $210 million, driven by a mix of operated and nonoperated incremental activity and partially offset by some savings achieved. With our own operations, we’re likely to have about 5 more wells drilled and 1 to 2 more completed as compared to the March outlook. We’re also seeing a modest pick up in nonoperated proposals from adjacent producers.

Incorporating these updates and based on confidence with the assets and optionality inherent with the development program, we’re raising full year production volume guidance ranges by 5% to 22,500 barrels per day at the midpoint, corresponding with the 30% year-over-year growth that Bobby mentioned at the start. We see that growth beginning modestly in the second quarter, followed by the largest gain in the third quarter and another gain in the fourth quarter. Accrual CapEx looks to be weighted 60-40 between the first half and the second half of the year, while production volumes will have a lag effect given the nature of development and turning wells to sales, with oil forecasted volumes weighted at 45-55 for the first half, second half. This combination may lead to less free cash flow in the second quarter with stronger free cash flow in the fourth quarter.

So this is dependent on execution, timing dynamics and market pricing. For the full year, we forecast a reasonable CapEx reinvestment rate of approximately 65% to 70% of operating cash flow before working capital and midpoint guidance and based on current forward oil prices. We anticipate the majority of excess free cash flow after the dividend will be allocated to debt paydown to further solidify our balance sheet and to provide future optionality with a smaller amount possibly allocated to stock buybacks depending on market conditions. Our measure of capital efficiency may differ from some larger companies looking to prioritize and maximize free cash flow, which implicitly calls for restrained investment. We’re excited to invest meaningfully this year in our high-returning assets, which we believe will yield this differentiated growth profile that we’ve described today.

Thank you all for your attention and interest in our company. Operator, you may now turn it over to questions.

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Operator: [Operator Instructions] Our first question comes from the line of Derrick Whitfield from Texas Capital.

Derrick Whitfield: Congrats on a strong 1Q and 2026 update broadly. First, I wanted to focus on your activity plans as we’re clearly in a very fluid situation in the Middle East. With today’s revised activity plan and workovers and recognizing the strength of your — and the growth of your program as it stands, how would you characterize your desire to further lean into this favorable environment from a workover perspective, nothing more? And then as you look out to 2027, is this level of activity a good run rate for the efficiency of your operations?

Bobby Riley: Derrick, this is Bobby Riley. Let me start. Like I mentioned in our deal, when we looked at our activity level this year, we were faced with about a $60 current price and $60 outlook. And we thought at those numbers, we warranted developing at the pace that we are. I mean, like we talked about in the last couple of years, we’ve been in the acquisition mode to build inventory. And now we’re sitting on a significant amount of long-term drilling inventory and the ability to capitalize on that value even at $60. So we would have to see a significant drop to adjust the direction we’re going now. And with the efficiencies that we’re seeing in drilling and completions, with sustained price in this level, we could actually add another 5 or 10 wells for the next 3 months. So I mean, we’re a growth company. And I think you’re going to receive long-term share value, the bigger we get organically. It’s our highest rate of return.

John Suter: Yes, Derrick. And to follow up on one of your other questions, can this efficiently move into ’27? I think this year, we’re running 2 rigs really just to hold a few things in New Mexico with some permits we had expiring and some lease obligations. But really just the fact that with our fast cycle times when we can drill 50-plus wells a year with 1 rig, we can easily do that. And certainly, a frac crew can frac up to, I don’t know, gosh, 90 to 100 wells per year. I mean it’s that efficient. So it doesn’t take a lot of extra service company action for us to be able to stay at a pace that provides tremendous growth if we plan to just keep it going all year long. It’s really not a matter of how much we add. It’s just how much we use what we have for how long during the year. So I hope that helps.

Derrick Whitfield: It does. Makes sense. And then just based on your current 2026 upstream capital plan, how should we think about the potential earnout of contingent payments from your midstream sales agreement? And when could you start to recognize that benefit?

Philip Riley: Yes, Derrick, this is Philip. I think we have line of sight on that for early next year. The wells that John and Bobby are talking about in New Mexico, we’ve got a slug of those that will come on. There’s a threshold that we cover for a period of days and then there’s a little timing. But we feel pretty confident about hitting the first earn-out, which is $30 million in the first half of ’27, with subsequent ones probably a year after each.

Operator: Our next question comes from the line of Neal Dingmann from William Blair.

Neal Dingmann: Sticking with the production question. My question is on your growth. I know, Bobby, for you or Philip, I know operationally and financially, you certainly have the ability to materially increase production if you choose. I’m just wondering how much is the decision and kind of the guide you talked about, how much is that influenced by — you’ve had negative natural gas and NGL prices? And how much do other things like, I don’t know, incremental takeaway or power fit into this growth decision?

Philip Riley: Sure, Neal. I can start. Yes, look, the gas, it’s frustrating, but we do see it getting better. I think what we and other producers experienced in the first quarter was a combination of the structural constraints I mentioned in prepared remarks and then some of that seasonality. You look at the strip, and it is getting better each month. We’ve got about 5 Bcf a day coming on among those projects that are widely discussed, GCX, Blackcomb and Hugh Brinson towards the end of the year, that should help. And then at the same time, I think you typically find the correlation between gas price or the Waha price even and oil price with most of the growth in our domestic gas coming from associated Permian. And so as the oil price is moving down here, I think the Waha price will become less negative.

Like I said, it’s frustrated not to be making more, but it still does — margins and returns look very good at $70, $80 oil. So we’ll continue with that. As far as there being a physical constraint, we’ve got the items we need lined up. John referenced some of that and power doesn’t seem to be a problem right now. We’ve got both what we need, what we’ve built out solidly, but then you’ve also got the short-term type of generators and such that can even run on natural gas, which is quite economic these days.

Neal Dingmann: Great. And then, Philip, just a second question on — maybe for Bobby on M&A. Just wondering, much like organic growth, you certainly have the balance sheet now to support really an active M&A program if you choose. Just wondering are there active deals out there? How do they look in this environment? And maybe just with that same vein, what — where does your current inventory depth sit?

Philip Riley: Yes, I’ll start on the M&A first. So typically, what we find in our industry is that M&A is tough in periods of high volatility. The high prices themselves are not a deterrent, but it’s hard to underwrite when prices move around so much. When the prices were quite low, sellers were on the sidelines. I think we’ll see a few more packages come to market at the high prices for people to so-called test the market. It can be tough to underwrite them, though, both with the volatility and even some steep backwardation. So we want to be careful. You’re right, we do have a stronger balance sheet, and we have flexibility to do that should something come together. But we want to be mindful of how we’re both underwriting deals and where in cycles we’re buying them.

We felt great about buying Silverback last year at $60. As I mentioned before and we feel good about that. We’ve done 3 deals in 3 years. We’ve got quite a bit of inventory. We’ve held back on the CapEx for a while as we digested those and got the infrastructure ready. And at this point, we’re focused primarily on the organic development. And I think that’s how you should think about it. It’s primarily organic. If something should come together on M&A, we’ll feel fortunate, but not holding our breath.

Operator: Our next question comes from the line of Jeff Robertson from Water Tower Research.

Jeffrey Robertson: Bobby or John, can you talk about the guidance of the production uplift in the sense of how much of the increase is due to timing versus performance-related issues with the wells that you’re bringing on?

Bobby Riley: Let me start, John, and then you can finish. Obviously, the acceleration is something to do about timing. We’re — we currently have 2 rigs running with a frac crew right behind one of them. So we’re bringing things on a little bit quicker. But also performance so far that what we’re seeing this year, I think all the wells that we’ve completed this year exceed our predrill forecast, some of them significantly. So John, you might add to that. But I mean, I think it’s a combination of working a little faster and the wells are meeting or exceeding our production expectations.

John Suter: Yes, absolutely. And just to follow that up with a little bit more specifics, we’ve drilled a number of 2-mile laterals this quarter, which have just been fantastic. You hope you — a lot of times, 2 miles will keep things flatter, but we’ve actually seen some uplift in pressure and rate from these. So we’re excited about that. Also, we’ve — in Champions, the vast majority of our wells are child wells. And these wells, we’ve been finding out tend to cut oil faster and reach a higher oil peak sooner than our parent wells, which ends up delivering superior early time performance. So that’s a lot of what we’ve seen this quarter to hopefully answer your question.

Philip Riley: And then let me say one final thing, Jeff, on timing as far as how it all comes together for the company and in the quarters is we do have quite a bit of back-end weighted growth. So the first quarter, we’ve gone through that was roughly flat with the fourth quarter. We’ve got some modest growth here, 4% in the second quarter at the midpoint. And then it really starts to take off you can back into the math between what we’ve done so far and what we’re guiding to full year. But you can see that the back half of the year is basically between 24,000 and 25,000 barrels a day, which suggests pretty material growth from where we are now and what we’re guiding to.

Jeffrey Robertson: Well, if there’s any risk with respect to the production outlook in the second half of ’26, is there much risk or much cushion built in for timing issues around Targa completing the projects?

Philip Riley: Yes. I think we’re in a good shape. As Bobby said earlier, we’ll be doing Texas primarily. We’ve got some optionality built into the plan. John was describing how he’s going to have some DUCs ready. But we’ve got a plan basically to hit this, so we believe should the timing work out either way. John, do you want to add anything there?

John Suter: Yes. No, I mean, I think our Champions development is going to carry the day all throughout the year. But we expect the permit for Targa for the high-pressure line to come any day, which then will be a several month period of construction. And that’s why we’ve said in Q3, it could happen slightly faster. But even if there’s a delay in that, the high interest Champions wells where we already have infrastructure, that’s going to solidify that second half, I think. But the New Mexico stuff will be kind of gravy on top of that.

Jeffrey Robertson: John, with plans to drill 42 to 48 net wells this year. Can you talk about how your ground game is working to replace inventory?

John Suter: Yes. Well, we are drilling some wells on the east side of Champions, and that is — we’re just now completing them. We’ve been buying some extra acreage out there, and we’re really excited to see where that could lead us on the east side. But in New Mexico, really, we have very few PUDs booked. So there’s going to be — as we drill some of these wells, we add PUD reserves. And certainly, as we test various edges of the fairway, that’s going to lead us to have the potential for additional leasing. What I love about New Mexico is that it’s a forced pooling state, and we probably have 500 gross sticks, maybe a few hundred net. But with an active rig in that field, you can pick up — oftentimes pick up a lot of interest from other people. That all just depends as we know, but we’re excited to be an aggressive player out there in the Northwest Shelf and to hopefully be rewarded with picking up interest.

Jeffrey Robertson: Lastly, LOE per BOE was $7.51 in the quarter, which was well below your $8 to $9 per BOE guidance. Can you talk about the drivers for that first quarter performance?

John Suter: Yes. As I mentioned in my remarks, we’ve just in the first quarter, capitalized on some rebidding and some realignment of vendors. And in New Mexico, I think we’ve cut our per barrel chemical cost in half with this new change. Also straightened out some things in Texas. This chemical program has also helped us from — it’s actually working. That’s less tubing strings you have to replace less ESPs to replace when you have to replace the tubing. So that really starts having a cumulative effect. And on the other side, the productivity of these wells has also helped us with, I’d say, some volume expansion has helped us on the divisor side of that per BOE metrics. But look, we’re proud of what we’re accomplishing. I think we’re one of the best operators on the Northwest Shelf, put our team up against anybody as far as being able to get the most out of the wells that we purchase and the acres that we exploit. So no, we hope to make continued improvement.

Operator: [Operator Instructions] Our next question comes from the line of Nicholas Pope from ROTH Capital.

Nicholas Pope: Curious as you kind of look at the differences between Champions and the Red Lake area with one rig kind of running in each. What’s the difference, I guess, in kind of total drilling complete costs between the 2 assets? I think it’s — there’s a lot of mix going on between these 2, and it seems like it’s shifting a little bit throughout the year. So I just want to make sure I kind of pinpoint kind of the spend differences between the 2 assets.

John Suter: Yes. Typically, we drill 1.5 miles wells in Champions just because that’s the — that’s how it was set up. And in New Mexico, we’re pretty well generally limited to 1-mile laterals. Again, it’s not impossible that if things line up right that we can drill more. Remember that New Mexico is at about 3,500 feet TVD. So 2-mile wells are possible, but you really can’t do a whole lot of kickout and then drill 2 miles when you’ve got that little bit that small of a vertical segment. So cost-wise, it ends up being about, I’d say, $1 million more in New Mexico per lateral than it does in Texas. And I’ll say that’s at the moment, we are doing a ton of testing. We’ve done spacing tests. We’re doing frac tests. The thing that makes New Mexico a bit more expensive is that in Texas, we do cross-link fracs there in San Andres.

And in New Mexico, in the Paddock and Blinebry, we primarily do cross — slick water fracs. The slickwater fracs take a lot more fluid, more pump time. And so we are looking and have already performed cross-link frac on a recent test are really encouraged about that. So there’s more to come on that in the future. I mean, that in itself could be $0.5 million plus savings per well. But again, we also want to see what is the most oil recovered and be efficient in recovering our resources, too. So a lot of testing going on there in New Mexico, and I feel comfortable that our costs will be coming down over time. But that’s kind of the primary difference between the 2 assets at the moment, cost-wise.

Bobby Riley: Let me add one thing to that. In Texas Champions, we own roughly closer to 100% of each one of those wells that we drill in New Mexico, it’s significantly less. So we have to drill a lot more wells to get the same net impact to make sure everybody understands that it’s not one for one. We could have 50% to 60% working interest in New Mexico where we have 100% in Texas. So don’t be alarmed by the well count because on a net basis, it seems more reasonable.

Nicholas Pope: Got it. And then kind of digging a little bit deeper into kind of the rig cadence that you all are talking about with the Targa plant kind of scheduled start-up, it sounds like — I’m just curious what stage you’re getting the New Mexico wells to? Is it just purely drilling state in the completion for once the Targa plant comes online? And I guess, how many, I guess, wells are you all anticipating kind of having ready to go upon start-up of that Targa plant? It sounds like things are going to be held back until kind of you can let the field breathe a little bit.

John Suter: Yes. So in New Mexico, we started up a rig at the end of the first quarter, I believe. And you’re correct. We are drilling and getting these wells ready for completion, but just in sake of capital efficiency, there’s no use completing them and letting them sit there until late Q3. And so we’ll take a look at that as far as whether we start a little bit early fracking these wells, kind of depends on what the oil price is at the time and a number of other things. But we should have 20-plus wells. Again, these drill so fast that you’re drilling a well a week and skidding over and knocking a whole pad out that way. So it should be 20-plus wells plus a substantial amount of volume that we have from existing PDP that’s already there flowing to another processor.

So when we get all of those wells that we’re drilling in ’26 now ready to go, we’ll be a long way towards getting that volume to meet that first earnout. We do have to produce it steadily like that for over a quarter or for a quarter to get that earnout. So like Philip said, maybe the end of the first half of 2027.

Operator: And our last question comes from the line of Noel Parks from Tuohy Brothers.

Noel Parks: I did hear you mention earlier that you had seen some modest pick up in non-op participation, I think, from adjacent partners. So I was just interested in that I had heard something I think from another operator and just thinking maybe the decision-making is a little different compared to — in the current price environment compared to how public operators are approaching the environment.

Philip Riley: Yes, I’ll start. Yes, I think you said the right word, public. So this is in New Mexico where I’m referencing that, and it’s dynamic, John mentioned, which is forced pooling. You’ve got generally just more chopped up ownership, overlapping ownership, and it’s not uncommon to participate in each other’s wells out here. We got the majors, the largest oil companies in the world participating in our wells, to be honest. So yes, we’ve got a couple of proposals from some private operators, whether that’s a coincidence or not relating to their desire to increase activity. It may just be this was somewhat on the plan. We weren’t sure exactly when it come, but now they’re here. So yes, we’ve got a few proposals. Those are coming now. We’re happy to do it. These are great returns. No reason not to participate in those.

Noel Parks: Okay. Great. And actually, I guess it goes for both New Mexico, we’re talking about, but also interesting thinking about Champion. How many operators are also actively drilling in your vicinity for each area?

John Suter: Yes, I’ll take that. I would say in New Mexico, it would probably be 2 with — one of them more sustained and the other one just every now and then. And then in Champions, we are by far the leading driller there. I think there is another company that might drill, I don’t know, 4 or 5 wells a year. Yes, 2 at most, but they really don’t compete with us in the direct area.

Noel Parks: Okay. And not so much thinking about large-scale M&A, but just from an A&D perspective, is there — I mean, I guess if you’re — if the burden of the land work and so forth is going on, is there considerable extra inventory just from — I don’t know if it’s say abandoned properties, but just since especially Champions is such an old field, is there much else to do if the ownership could be, I guess, concentrated, bought out, out there?

Philip Riley: I’ll attempt to answer that. Champions, I’d say, it’s mostly blocked up and spoken for. Look, all of this, I think, whether where we are in Texas or New Mexico or most likely throughout the Midland and Delaware, you have a few areas where there’s just available unleased land, right? People have discovered where the resource is and have gone to try to capture that. There’s always some work to be done to get that, and we give our thanks to our land teams to get that done. I think that’s some of just the magic that happens with producers is getting that ready for drill and development. But it’s a function of kind of piecing those together and getting them ready, finding whether it’s old records or title or what have you. But it’s not so much that it’s just available and somebody hadn’t thought to get it yet.

John Suter: Yes. And I’ll add on to that. But one thing to bring up in Champions that yes, we do control that, and we’ll be drilling most all of that. As Bobby always mentions, there’s a lot of upside left in Champions even once that thing is fully developed. I mean, we only recover 8% of the oil typically on primary. But it’s a field where I think you’ll find a lot more oil to recover once we deplete the pressure down a little bit where other techniques will benefit getting more oil out. And then certainly, in New Mexico, Bobby said we may have 60%, 70% of a lot of that acreage. There’s always people willing to sell in the right situation or to trade. So there is upside there, too, from either acquisition or just some good land work.

Bobby Riley: Also, we look at adding inventory when we’re analyzing different benches and it’s not so much in Texas, but in New Mexico. There is some work being done in one of the upper benches that could significantly add inventory.

Noel Parks: Great. And just to clarify, is that — when you talk about alternate benches, are those things that have sort of similar deposition to the benches you’re producing? Or are they more intermittent up there?

Bobby Riley: It’s pretty much the same. It’s just adding another zone that’s been tested and produced vertically, adding it into the mix. So we’re looking real hard at the number of wells per section that we’ll be drilling in Texas, including based on our spacing test. We could be adding an additional Blinebry or maybe an additional Paddock and then additional uphole zone. So we’re still actively — I would not be concerned about the ground game. There’s plenty of opportunity for us to add stick in addition to the numerous other organic projects that we have in-house.

Operator: Thank you, everyone. That concludes our conference call for today. You may now disconnect.

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