Riley Exploration Permian, Inc.REPXNYSE
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Operator: Ladies and gentlemen, thank you for standing by. Hello. My name is Dustin, and I will be your conference operator today. At this time, I would like to welcome you to Riley Exploration Permian Inc. Third Quarter 2025 Earnings Conference Call. [Operator Instructions] I would now like to turn the conference over to our CFO, Philip Riley. Please go ahead, sir.
Philip Riley: Good morning. Welcome to our conference call covering our third quarter 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.
Bobby Riley: Thank you, Philip. Riley Permian delivered another solid quarter marked by disciplined execution and strategic progress on multiple fronts. In July, we closed the Silverback acquisition and began integrating the asset where we are already realizing synergies. In just a few months, we have reduced costs and increased production. For September and October, combined production on the acquired asset exceeded our underwriting case by more than 50%. We executed our development and capital plan during the third quarter, which contributed to significant free cash flow generation. Over the last 9 months, we have generated $100 million of upstream free cash flow, approximately flat compared to the same period a year ago despite a 14% lower realized oil price. We continue to progress our midstream and power generation projects, securing equipment and advancing build-outs. These critical infrastructure projects should enable Riley Permian to scale operations in 2026 and beyond. Today, we are paying our 19th consecutive quarterly dividend as a public company. In October, we increased the dividend to $0.40 per share, up 5% from the previous quarter. Maintaining a consistent and growing dividend underscores our commitment to capital discipline and focus on sustainable free cash flow. With that overview, 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 and forward-looking guidance.
John Suter: Thank you, Bobby, and good morning. Riley Permian has once again shown its commitment to safe operations, achieving a total recordable incident rate of 0 in the third quarter. We achieved 93% safe days, a metric requiring no recordable incidents, vehicle accidents or spills over 10 barrels. As for activity, in the third quarter of 2025, we completed 5 and turned in line 10 gross operated wells. 5 of those wells turned in line were completed at the end of the second quarter. Average daily net production was 18,400 barrels of oils per day and 32,300 barrels of oil equivalent per day for the third quarter of 2025. Oil volumes increased by 3,200 barrels per day during the quarter, benefiting from the addition of acquired Silverback volumes, incremental production gains from Silverback workovers, along with strong performance from several new wells on legacy acreage. Total net oil production increased from 1.38 million to 1.69 million barrels of oil quarter-over-quarter in Q3. This is an increase of 22% quarter-over-quarter and an increase of 19% compared to the same quarter last year. Total equivalent production is up 34% quarter-over-quarter from 2.22 million to 2.98 million barrels of oil equivalent and up 38% compared to the same quarter last year. Total equivalent volumes grew faster than oil last quarter for 2 reasons: First, because our Texas midstream partner completed some upgrades, which led to materially more gas sold; and second, with the contribution of the Silverback asset, which has a gassier mix currently. This will become more oily as we bring on new horizontal wells. At Riley Permian, we pride ourselves on being a low-cost operator. We nearly doubled our operated well count in New Mexico through the Silverback acquisition. Many of the acquired wells are lower volume vertical wells with a higher cost per barrel. However, we maintained LOE per BOE near $9 per BOE, which is only a 6% increase over Q2 and a 5% increase over the same quarter last year. We believe we can reduce costs further as a result of synergies we're realizing through the Silverback acquisition that we'll discuss shortly as well as increasing the mix of horizontal wells as we continue to develop. Riley Permian picked up a drilling rig in October, getting a head start on our development for 2026. We are drilling 8 to 10 gross wells in Q4, which will set us up for some early completions in Q1 of 2026. In addition to the drilling program, 3 to 5 gross operated wells will be completed in Q4, cementing a solid exit rate for 2025 and base production for the year to come. Our initial look at D&C pricing for the upcoming wells in our Red Lake asset is down nearly 10% over our last campaign in New Mexico. This is the result of softening of prices in both rigs and frac spreads as well as lower steel prices than realized earlier in 2025. Moving to midstream. Our gathering and compression project in New Mexico continues to add value in the form of increased flow assurance by reducing downtime and allowing us to bypass some of the legacy low-pressure systems in the area that struggle with reliability. In the fourth quarter, we plan to upgrade the initial compression facility we installed earlier this year with an incremental 40 million cubic feet per day nameplate compression capacity. This will allow us to utilize 15 million cubic feet per day in addition to what we're currently delivering to our existing provider, and we'll be able to utilize all remaining high-pressure capacity when our transmission line is in service in mid-2026. Low-pressure gathering lines are currently being installed to expand the input capacity to the compressor facility, allowing us to utilize the additional capacity that we will have by year-end. The high-pressure transmission line we're planning to install continues to progress. Permitting is submitted and underway and secured pipe is scheduled to arrive late in the fourth quarter or during the first quarter of 2026. Shifting to power. Our joint venture, RPC's project in Texas continues to grow in scope and improve in reliability. In the third quarter, we added 5% more of our total load to the generation in Texas with 100% uptime in September. In New Mexico, RPC is progressing on the plans for another behind-the-meter generation project. We've begun permitting, designating a location and securing long-term lead items, including 10 megawatts of generators. The pilot generation station as well as the distribution system will begin construction in 2026. We continue discussions to advance both water and oil infrastructure projects that will maximize our ability to control development pace. We also look forward to better realized pricing on our oil barrels as we consider moving away from trucking where opportunities exist. The Silverback acquisition is already realizing value through synergies and cost-saving opportunities since closing. We've been able to drive down fixed costs in the field through things like combining multiple field offices and managing headcount. We expect that those fixed costs will come down 10% to 20% following those and other changes. We mentioned last quarter that we intended to leverage our expertise in water handling to drive down costs in both Silverback and legacy Red Lake assets. In a few short months, we've seen a $70,000 per month decrease in costs due to our integration efforts. We're nearing completion of low-pressure gathering lines that will tie back some of the gas in the Silverback acreage to our compressor station we've built, allowing for better reliability, maximizing production from the area. Significant progress has been made in maximizing production from the asset. Without bringing on any new wells, the Riley Permian operating team has increased production over the purchase case forecast by over 50% for the months of September and October combined. This was achieved primarily through strategic workovers, returning wells to production as well as artificial lift optimization. We're pushing forward with several RFQ processes, attempting to leverage the larger economy of scale achieved through acquisition. We anticipate notable savings on frequently used materials such as steel tubulars and production chemicals as a result. Overall, it's been a very successful quarter for the operations team. We're progressing our efforts on both our midstream and power endeavors. We're already seeing costs come down on our latest drilling program. We're maintaining disciplined operating costs and all of this while achieving record levels of production. Congratulations to the team on a job well done. Philip, I'll now turn the call back to you.
Philip Riley: Thank you, John. Third quarter results reflect the Silverback acquisition given the deal closed on the first day of the quarter. The transaction was accounted for as a business combination. Cash paid at closing was $120 million, 15% lower than the $142 million unadjusted purchase price upon announcement, benefiting from cash flow from the January 1 effective date through closing as well as other favorable adjustments. Overall, company third quarter results were either within or favorable to guidance levels. Prices after hedges were roughly flat quarter-over-quarter and oil represented all of our revenue last quarter as we experienced negative natural gas and NGL revenues after fees. As discussed by other operators reporting recently, the industry experienced an especially weak September and October gas market in the Permian with select operators voluntarily shutting in an estimated 1.5 to 2 Bcf a day of gas production. LOE was higher quarter-over-quarter, driven by 2 primary factors. First, from the contribution of higher cost Silverback vertical wells that John discussed earlier and as I previewed on the second quarter call; and second, from increased workover activity associated with the positive results John described earlier, which drove higher corresponding workover expense. A quick clarification is in order here. Investors often associate most dollars spent supporting new production volumes in the form of capital expenditures, while we often opportunistically pursue workovers like these, which get expensed and are embedded in LOE on the income statement. Production taxes were higher as a percentage of revenue as more volume shifted to New Mexico, which has a higher tax rate than Texas. Third quarter administrative costs included transition costs associated with the acquisition and other nonrecurring items, which should normalize over time. On a per BOE basis, costs were squarely within the guidance ranges for LOE and administrative costs. We had nearly $5 million of favorable income tax benefits in the third quarter resulting from the new federal legislation, allowing for increased bonus depreciation, which we realized across our legacy assets, the acquisition and from our midstream project. Third quarter cash flow from operations before changes in working capital was $54 million, higher by 17% quarter-over-quarter, primarily from higher volumes and from slightly higher oil prices before hedges. Adjusted EBITDAX margin was 59%, down from 66% last quarter, primarily as a result of the cost items noted above. On costs and margin, consider that we've just closed the Silverback acquisition. Our team has made good initial progress and is excited by the potential to drive synergies and develop the asset. We're optimistic to lower our cost structure and improve margins over time. We take confidence in this potential given our track record in this area. Since the Pecos acquisition 2 years ago, we've reduced LOE per barrel for that specific asset by more than 30%. During the third quarter, we reinvested only 27% of cash flow from operations before working capital and upstream CapEx or only 36% for the 9 months year-to-date. Third quarter upstream accrual-based CapEx was nearly 40% below midpoint guidance as a result of some delayed non-op activity and infrastructure spending. Some of this will be shifted to the fourth quarter. We generated a very robust $39.4 million of upstream free cash flow in the third quarter, representing 73% conversion of operating cash flow before working capital. Year-to-date, we've generated $100 million of upstream free cash flow or 64% of free cash flow from operations, an amount equal to the same 9-month period for 2024 despite 14% lower realized oil prices. On our other projects, we invested $14 million in our New Mexico midstream project. And in power, we invested $8.5 million with the latter -- into the JV, with the latter being slightly over guidance as we simply accelerated most of the fourth quarter spend to secure some equipment. Year-to-date, we've allocated 31% of total free cash flow to dividends. Debt was $375 million at quarter end, corresponding to 1.3x leverage based on pro forma adjusted EBITDAX, including Silverback. Now I'll move to guidance. We're raising oil production guidance for the fourth quarter by 4% at the midpoint to 19,200 barrels a day. This fourth quarter oil production rate at the midpoint corresponds with 5% quarter-over-quarter growth and 21% year-over-year growth from the fourth quarter of 2024. This leads to a 2% increase in guidance at the midpoint for full year oil production to 17,100 barrels a day, corresponding to 13% year-over-year volume growth. We're maintaining guidance for full year total CapEx and investments at the midpoint at $92 million of accrual CapEx with some shift in spending from third quarter to the fourth quarter. The combination of increased production with flat CapEx evidences doing more with less. Fourth quarter drilling and completion activity will primarily drive 2026 results with only modest impact on fourth quarter volumes. D&C cost savings in New Mexico and some schedule flexibility allowed us to accelerate 2 completions from 2026 into the current quarter. These wells will support 2026 production with no impact to fourth quarter 2025 volumes. Looking to next year, we're striving to balance excitement around development potential in our asset base with capital allocation discipline in the face of softer oil markets. While some longer-term planning commitments are required, we'll watch the markets and aim to maintain flexibility with shorter-term commitments. We believe the current state of the oilfield service market affords such flexibility. Fortunately, we're in a situation that allows for resiliency and confidence across a range of prices. I'll offer the following examples based on preliminary forecasts. We believe we could maintain our third quarter 2025 oil volume level of 18,400 barrels a day over the full year in 2026, which would equate to 8% year-over-year growth while reducing 2026 upstream CapEx by approximately 15%. This scenario partially benefits from the fourth quarter 2025 forecasted volume tailwind of 19,200 barrels a day at the midpoint. Next, if we focused instead on maintaining upstream CapEx and not volumes, then we believe we could keep our 2025 upstream CapEx level generally flat while growing full year oil volumes year-over-year by approximately 12% to 15%. If oil markets improve, we can grow beyond these levels with increases in capital spending supported by our deep inventory of development locations. Finally, we forecast the dividend being well covered across these 2026 activity and oil price scenarios, benefiting from this capital efficiency and hedges in place. We have over 60% of 2026 oil volumes hedged at a weighted average downside price of $60 with upside optionality as 44% of hedges are in the form of collars. I'll turn it back to Bobby for closing. Thank you.
Bobby Riley: Thank you, Philip. Once again, we appreciate your time and interest in Riley Permian. While we're pleased with our Q3 2025 results, our focus remains firmly on the future. We are committed to creating long-term value through disciplined capital allocation, strategic infrastructure investments and operational excellence. We believe these initiatives will position us for sustainable growth and shareholder value. We appreciate your ongoing support and confidence in Riley Permian. Operator, you may now turn the call over for questions.
Operator: [Operator Instructions] And we will take our first question from Derrick Whitfield from Texas Capital.
Derrick Whitfield: Congrats on a solid overall print. Wanted to start with a bigger picture question on capital efficiency and capital allocation. As we think about Slides 5 and 7 and Philip's ending commentary, it's clear your business has differential capital efficiency and can accomplish an all-of-the-above funding strategy while continuing to grow in a relatively low to mid-cycle pricing environment. As you think about your cash flow priorities in a below $60 per barrel environment, how would you prioritize capital allocation in that environment? And are there pathways where you can continue to fund all 3 segments of your business while maintaining control of each?
Philip Riley: Yes. Fair question. Thank you, Derrick. In a $55 scenario, that starts to get to the point where on a corporate level, full cycle, we're mindful of spending too much. I think our half cycle economics, as evidenced there on that slide you referenced, can work down below $40, but there's no pressing need to develop that sooner. So I think in a $55 scenario, you're going to see us in that lower potentially volume maintenance scenario where we're spending sub-$100 million, maybe it's in the $85 million range. We can maintain volumes that way. We've got the dividend well covered. I think we are funding CapEx for the midstream find that way, and I can talk more about that in a bit, if you like. But that's probably a fair inflection point. I think there's also probably some psychology bias there at that inflection point of $55. Things below it start to get tougher for our industry. That said, it's never just a single variable equation. We'll see how the oilfield services market reacts. Some believe that their costs won't go lower, but you never know. Should those continue to decrease, then that can change some of the economics as well.
Derrick Whitfield: Terrific. Yes, that makes sense. And maybe for my follow-up, I wanted to shift over to the New Mexico Midstream project. While the ability to control pace of development and flow assurance are the primary drivers, could you offer some color on the potential improvement you'd expect in netbacks for the upstream business and the amount of third-party volumes that could accrete value for the midstream business?
Philip Riley: Yes, I can start and then maybe, John, if he wants to fill in on some of the volumes. Look, on netbacks, this is never a binary clear impact. I think the way that works is, first and foremost, we start with the flow assurance. We're getting into good systems there, newer generation gathering compression pipe and their facilities. We think we're going to get some economic improvement based on more efficient, best-in-class type of processing and treating facilities. So we've got some of that modeled that we hope to realize. And then the netbacks themselves, sometimes what that involves is making an additional commitment to get to capacity basically by your way into some capacity that reaches the Gulf Coast. You see some companies -- I think there's a company hosting a call at this exact time that's done that, where you make a commitment to the midstream counterparty for that capacity, and they can offer you a bit closer to the ship channel pricing. Now there's a negotiation involved. And not everybody can do that because clearly, most of the Permian would like to have the ship channel versus the Waha pricing. But I think it represents a spectrum. We hope to get some of our gas closer to that, but it will be something that takes place over time.
John Suter: Yes. Derrick, I'd like to add from an operational perspective, I think this midstream project is just a must-have for our company to be able to grow the New Mexico asset. I think not only are we going to get a little bit better processing outcome from the new provider, once we put about $15 million more into the -- as I said in our initial discussion, that will be all that current provider can handle. And so there will be -- without gas decline, there will be no more room. So this really allows us with $150 million to $200 million more capacity within this new line I mean it's going to let us do what we're -- our main objective to drill oil and gas wells. We'll have a home for our product. So it really is a must-have. Again, we can -- right now, our pace is very limited in New Mexico just because of that. So given that new capacity opportunity, then we can make the choice as commodity price swings, as our value from making more oil and gas is enhanced, we can step it up and fill that need quickly.
Operator: Our next question comes from the line of Jeff Robertson from Water Tower Research.
Jeffrey Robertson: Bobby, maybe to follow up on your last comment is essentially the midstream project, once it's completed, will allow Riley to produce more oil because you can more -- you can pace the development of your field however you see fit with commodity prices since that's where the -- at least currently, that's where the real value is. Is that the right way to think about it?
Bobby Riley: Absolutely. I think that was John that was talking there, but he's right on point. I mean, our objective is to get unconstrained takeaway capacity for both gas, oil and water so that we have full flexibility in our pace of development to develop the asset. I mean we've been drilling some pad locations with anywhere from 3 to 5 wells coming on at the same time. So it's a substantial bump in all of those -- that commodity mix all at one time. So the track we're on is just to get us in a position to have all options on the table.
Jeffrey Robertson: Philip, can you talk about the capital spend for the midstream project completed in the first half of 2026 and then how that impacts your free cash flow flexibility in the back half of the year with that burden behind you?
Philip Riley: Yes, sir. So I think this weaves into how I -- in my prepared remarks, talking about some of those maintenance scenarios and the level of spending there. If you look at what we've disclosed in the very beginning of 2025, we saw spending roughly $130 million on this midstream project to get it completed with the pipe and through initial areas in our kind of core development area. Since buying Silverback, we could expand that, but we don't have to do that right away. So we're considering a number of options, Jeff, if we bump along in this kind of $60 level or even a little bit low, we're going to be watching the prices and watching our cash flow. We could maintain the status quo and keep this on the balance sheet. I think based on the scenarios I described, we can be roughly free cash flow positive even after combined upstream and midstream CapEx. So maybe that's somewhere in the $170 million to $180 million range or possibly just short after the dividend at kind of $60 WTI, in which case, you've got a slight deficit there, but you've got plenty of capacity because you are creating value. So we take comfort there because we've created real asset value. We've got an implied $120 million, $130 million of spend there into the midstream at that point. And so because of that, I guess I could segue, we're also considering some financing options at the project level. We've considered using a credit facility. Our existing credit facility is an RBL, reserve-based loan. It allocates 0 value to the midstream assets right now because it's all about the upstream reserves. But there very much is material hard asset value there. As I just described, it could be a cumulative basis, $120 million, $130 million of book value by the end of next year if we proceeded with that. We've also considered bringing on an investor partner, which could take different forms. And so we've had those and other options that we're working through. We take confidence that we have a number of alternatives. Nothing has been definitively decided at this stage.
Jeffrey Robertson: So if you went some sort of project route and any economic benefit from third-party volumes would flow through that type of entity. Is that right?
Philip Riley: Yes. And just to be clear, I'm talking more capital partners, Jeff. We can -- we could have third-party operators that could come through the pipe, and we could sell them some capacity, in which case we're collecting more fees. That's something that's possible, too, and that's something that helps with -- that's something that would help with revenue and cash flow over time, but not with the upfront capital to build the project. That has its pros and cons. Pros is you got true third-party incremental revenue there. The balance is with Silverback and the size of our footprint now, I mean, we see potential to fill up the entire capacity by ourselves. Now that takes time to do it, maybe it's 7 or 8 years. And so the question then is, do you sell some of that capacity for a shorter-term basis? Do you sell it for a longer-term basis at a higher price? Do you expand this and so forth. So it's kind of an organic thing that we're working through. But going back to the capital, we'd be looking at some capital type partners that could come in different forms, whether it's an equity or credit.
Jeffrey Robertson: And lastly, on production on the Silverback assets, John or Bobby, is there more to do on those assets to continue the solid performance that you had in September, October in terms of workovers and lift optimization and those types of projects? Or have you done the most obvious projects to this point?
John Suter: Yes. This is John. No, I would just say we've barely touched it. We've just gotten some obvious things where wells were offline when we took it over. They had gone through this divestiture process a while. So missing a little TLC that we have found just some easy things to do, but we've also tried bringing over some of the more technology based, the way we do our cleanouts that we think are different from what other people do and have had some really nice success on a couple of those. We obviously have several hundred wells that we can work on. I think there's probably like 30 horizontals and upper 200s of vertical wells. So there's quite a bit of playground there. We're frankly just very excited about it.
Operator: Our next question comes from the line of Nicholas Pope from ROTH Capital.
Nicholas Pope: I was hoping you could expand a little bit on that last question. Just kind of looking at the workover, John mentioned that, that was a part of operating expenses being a little up for the quarter, just a lot of opportunity. Just trying to quantify a little bit how much, I guess, workovers were as a percentage of like total operating expenses for the quarter and like how you anticipate that split of OpEx kind of over the next year or so?
Philip Riley: Nick, I'll take a first stab at this. I think this quarter, it was a few like probably $3 million -- $2 million to $3 million higher than normal. The reality is this is always in there. Sometimes it's a nature of our wells versus a shale, but we're always doing workovers. Last quarter was relatively light. And this quarter, we did more. You only see that on the line called lease operating expenses. But I think we had something like $8 million to $9 million total here of workovers. And so on an incremental basis, that was probably $2 million to $3 million higher than the prior quarter.
John Suter: Yes. For instance, workover was 59% of total LOE this quarter versus last quarter, 27%. And I think it tends to range more in the 45%, 50%. So really, there was, I think, $5 million. Silverback came in at around a $13 per barrel cost versus our 2 assets typically average more in the $8.50 range. And so that kind of tells you how that blended up to a little bit over $9 per BOE total LOE with, again, workovers being typically 40% to 50%.
Philip Riley: And just to add a final point there, just how we manage the groups is that this is a mix of reactive and proactive work. Reactive is something shut is down, and it's a big miss. But proactive to go out and do these exciting projects, the groups are given a budget and we can monitor with real-time analytics and stuff, how our costs are coming in for the month, and so they have certain budgets to work with. And that's a way we can have that vacillate from quarter-to-quarter, but then come out smooth on the overall cost per BOE.
Nicholas Pope: That was very precise. I appreciate it. Looking at the activity, no drilling this quarter, bringing the rig back, I guess where is the focus of kind of that near-term drilling with the rig coming back to start drilling right now?
John Suter: Yes. So we're over in champions in Texas. Like I said, we've got 8 to 10 wells coming by year-end. This will kind of refill our inventory of DUCs that we will use to complete -- gives us a great bit of flexibility with this whole commodity price challenge. So we'll be able to frac these things as we need them, kind of move that throughout the year depending when the markets are in our favor. So we have that. And around the turn of the year, we will shift our focus to New Mexico, and we will plan to start drilling a program there. I think we've only drilled 12 wells in New Mexico in the last 1.5 years that I've been here, and we've had some great results there so far. So I'm excited to get back and prove out some more territory there.
Philip Riley: And then on the turn-in lines, Nick, the first half of the year next year will generally be Texas. The second half then would be New Mexico contingent on our pipe coming online around midyear. Again, we've got that flexibility with the DUCs, as John described, to throttle those more or less based on price or if things are faster -- if the project is faster or slower around the midyear.
Operator: [Operator Instructions] Our next question comes from the line of Noel Parks from Tuohy Brothers.
Noel Parks: I was interested to hear your thoughts earlier about some external financing possibly being in sight. And we're in such a sort of unusual uncertain macro environment and interest rate environment. And I was just wondering, as you consider that project level financing, are you talking to pretty much usual suspects, the names we would kind of all be familiar with? Or I was wondering if you're seeing interest or capital coming in from more unexpected players or new players?
Philip Riley: Sure. Let me take and respond to the first half of the question, which I think was a comment about the uncertain macro and economic situation. I admit and agree that the upstream energy industry is out of favor at the moment. It's a tougher situation on the equity markets. Credit markets, whether for upstream or the wider market are very, very healthy right now. This is on the upstream, just real quick. We've had a lot of consolidation. So a lot of paper has come off from the banks. They are really wide open lending. High-yield markets, bond markets are wide open again, generally and upstream, we've got some very, very low spreads. That's not exactly what we're looking at here, but it just gives some context. What I'd also say is, aside from just pure upstream, there is a tremendous amount of appetite for capital for interesting new projects, infrastructure projects. If I go to the extreme, we look at what's happening with the hyperscalers, AI and data centers, and you see the tremendous amount of capital being thrown at that. Well, that's -- we're on the spectrum there of an infrastructure asset midstream being much easily -- more easily financed than upstream typically. We've got some real hard asset value here. We're going to have some contracted volumes and values, and that's something that you can lend against. Like I said, the credit facility currently has 0 allocated value for that. And so there's some debt capacity there. So just one example to start is just a plain vanilla bank is happy to do some lending there. Down, we don't talk about it because it's not in our financials directly, but our JV partner or our JV, RPC Power, has a plain vanilla credit facility with a regular way bank for financing some of that. And that's 7%, 8% cost of capital. Something like that could be available for midstream or if we wanted more capital, we could bring in a type of private capital investor who could be investing in some kind of common or preferred if we structured it that way at the midstream level. You can go look at case studies of different groups that have done this at those midstream projects. Private capital providers are excited to do this. I'm probably going to get a lot of calls after this is done just for saying this. But yes, they're excited to do that, and that represents something between credit and equity. And then you've got just pure common equity if you wanted someone to be really investing all of it. I hope that helps.
Noel Parks: Very much though. Sort of staying on that topic of where there's a lot of interest these days. I'm just curious, compared with a few years ago when you decided to go forward with the power JV, mainly with an eye to your internal needs, first and foremost. And today, when it seems now that the sky is the limit for any sort of gas-fired generation any place, anytime, anywhere these days. Just wondering if any conversations you're having on the power side, maybe around local generation or regional generation for possible data center projects and so forth. Just wondering how the environment and the conversation is different now compared to when you were first going forward with the project.
Philip Riley: Right. So we're very grateful that we got in, feel fortunate that we started this over 2 years ago, nearly 3 years ago at this point. So clearly early there. And clearly, the environment is very, very different now, both nationally and in West Texas. And so some of that, we feel happy to have the thesis validated, but ultimately, that doesn't matter, and we just want to make money. On new projects, look, we're -- I think we're taking a balanced approach. We've got a relatively full plate at the moment, but we're always looking for new places to invest our time and capital if we think we can earn a good return. Just to be a little cautious with so many people coming into the data center space, we want to be mindful of what incremental value can we add there. And then on a return of capital and cost of capital, typically, the more people you have to come into something, it gets crowded, it pushes down returns. We just have to be sufficiently comfortable and confident that we can earn a return of capital there. That competes with our core business and such. And then finally, if it's something that we did want to do, do we do it as a developer and so that you're getting this up to a certain critical stage and then effectively sell it versus if you decided to keep it on the balance sheet in perpetuity, we would have to believe that we get re-rated and that analysts like you suggest that we should be rerated to trade at a higher valuation because that would be embedded in our -- what's typically a lower valuation type multiple for, say, an upstream company versus an infrastructure or an IPP, which are trading at 12 to 15x EBITDA.
Noel Parks: Right. Okay. That makes a lot of sense.
Operator: There are no further questions. That concludes our question-and-answer session, and that concludes the call for today. Thank you all for joining. You may now disconnect.