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 2024 Earnings 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 one again. I would now like to turn the conference over to Philip Riley, CFO. Please go ahead. Good morning. Welcome to our conference call covering Fourth Quarter 2024 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 and 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 these 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. Good morning and welcome to our Q4 2024 Earnings Call. We had an exceptional year by all measures, and I am extremely proud of what our team has accomplished. At the start of 2024, we outlined a plan to grow oil production by 10% while reducing capital expenditures by 10%. Our actual results significantly exceeded these targets, with oil production growing by 15% and total production increasing by 22%, while upstream cash capital expenditures declined by 27%. Our 2024 performance underscores the capital efficiency of our asset base and the results of past infrastructure investments. We achieved these results while reinvesting less than half of our cash flow into our upstream business, which allowed for excess cash for debt paydown, dividends, and investments into midstream and power. In 2025, we will shift more development activity to New Mexico, where we see significant long-term growth potential. Thus, we are excited to advance our investment in the New Mexico midstream project. This strategic development will provide greater operational control over our gas gathering and regional transportation, enabling more robust development and access to multiple treating and processing plant networks to optimize our flow assurance. Additionally, we see commercial opportunities with third-party producers that could generate significant incremental revenue. In early 2025, we announced a 15-year gas purchase agreement and plans for a high-pressure 20-inch natural gas pipeline capable of transporting up to 150 million cubic feet per day. This infrastructure will secure our takeaway needs while accommodating future growth and third-party volumes, providing much-needed takeaway capacity for the region. Finally, we continue to make progress on our power joint venture, which was initially designed in 2023 to reduce Riley Permian's reliance on an intermittent and less reliable grid. We expanded the project scope in 2024 to include new power generation for the sale of energy into ERCOT, capitalizing on attractive market fundamentals within the Texas power grid. As part of our future-focused strategy, we will continue to invest strategically while maintaining balance sheet flexibility and preserving access to capital markets should additional actionable opportunities arise. Now I'll turn the call over to John Suter, our COO, to discuss operational results for the quarter, followed by Philip Riley, our CFO, who will discuss forward guidance. Thank you, Bobby, and good morning. Once again, Riley demonstrated excellence in operations through safe operating practices. The team achieved a total recordable incident rate of zero for 2024. We achieved 90% safe days in the year, a metric requiring no recordable incidents, vehicle accidents, or spills over 10 barrels. In 2024, we drilled 30, completed 20, and turned in line 22 gross operated wells. The additional wells turned in line are carried over from Q4 2023 completion activity. Our 2024 drilling and completion campaign achieved measurable success in both fiscal and operational metrics. We decreased our cost per foot across both Texas and New Mexico assets by 11% year over year in 2024. At the same time, we also increased our lateral feet drilled per day by 20% since 2023, setting records in Texas for both one-mile and 1.5-mile laterals. Of note, all wells that were drilled and completed in 2024 were on multi-well pads that had zipper-style completions, saving on rig moves and pump times. We continue to focus on driving drilling cost reductions through optimized bit selection, single BHA lateral runs, and minimized steering through better targeting, resulting in shorter spud to TD times. Other changes were made to optimize our completions, such as increasing cluster spacing and decreasing sand loading. These strategies allowed us to achieve higher efficiency and cost savings while maintaining or exceeding the production and reserve value of which our assets have shown to be capable. Net production grew from 4.8 to 5.52 million barrels of oil year over year in 2024, an increase of 15%, while equivalent production is up 22% from 6.79 to 8.25 million barrels of oil equivalent. Our average daily net production was 15.91 MBo/d and 25.03 MBoe /d for the fourth quarter of 2024. We continue to work with our midstream partners to maximize gas sales through strategic infrastructure projects and optimizations. Of note, we were able to capture and sell more of our produced gas in Texas, resulting in the same oil production but at a lower% of oil in the overall mix. This strategy in Texas has allowed us to drive full-field development at a pace controlled by us, allowing us to be flexible to market conditions and other industry considerations. We will continue to utilize this approach as we develop our New Mexico assets. This value creation is the main basis for our added focus on infrastructure in 2025. The production increase was achieved while maintaining low operating costs. Our LOE per BOE for 2024 was $8.66 per equivalent barrel, roughly flat with the 2023 full-year metric. Routine clean-out workovers have gotten more efficient in our Texas asset as we've continued to refine our operations. These efficiencies include timing of workovers, optimization of chemical treatments, and tool selection. As a result, our clean-outs cost 33% less than they did just two years ago, and we begin doing them proactively, resulting in higher production for longer before intervening. Overall, Texas workover expense is down 16% year over year on a per BOE basis in 2024. Also, in 2024, we completed our New Mexico plugging requirements that came as a part of the 2023 acquisition on schedule and within budget. This will result in a substantially lower spend for ARO in 2025. Related to the midstream development that Bobby discussed, the fourth quarter of 2024 saw the initial construction phases of our New Mexico gathering and compression project. Commissioning of the compression portion of this project is currently underway, with the first high-pressure sales before the end of this month. We will begin the project with roughly 15 million a day compression capacity to our existing gatherers' high-pressure system, and in the process, leaving an additional low-pressure capacity to fill in the interim. Further compression, gathering, and transmission infrastructure will continue to be built out over 2025, increasing our ability to deliver gas consistently and reliably. We continue to utilize our power generation station with a greater percentage of our existing Texas assets. We're currently using roughly 20% more self-generated power than at the end of 2024. This lets us control our Texas development plan without relying on utilities to drive our development timing. We're evaluating the benefits of a similar installation in New Mexico. In summary for the year, we produced 22% more equivalent production, spent 13% more net wells, turned in line 28% more net wells, operated with flat LOE per equivalent barrel, and spent 19% less C&C Capital dollars, all while delivering stellar safety metrics. It was an impressive year for safe, efficient, and technically driven development of our asset base. I want to congratulate the Riley Development and Operational Team for a very successful 2024. Philip, I'll turn it over to you. Thank you, John. I won't address the 2024 financial results as most are straightforward, but I'll add some color on new disclosures and metrics. Beginning with the most recent financials and then forward guidance, we've separately listed midstream capex, which in turn allows us to show a pure upstream free cash flow metric separate from total free cash flow. Upstream free cash flow is the residual cash flow after reinvesting capex in upstream assets for production volume maintenance or growth outside of acquisitions. We believe this transparency will be helpful to shareholders given the different stages of maturity of our upstream business, which is well established as compared to these newer midstream assets. For most capital-intensive businesses, the ability to generate positive free cash flow will be correlated with the maturity of the business, with early-stage businesses often having growth capital investments exceeding operating cash flow. To apply the example, we allocated upstream free cash flow in 2024 as follows. 38% was allocated to additional growth initiatives, including 15% to an upstream acquisition, 14% to our Power JV, and 9% to the new midstream project. 38% went to debt reduction, lowering debt by $90 million year over year to one-time leverage at year-end, with a final 24% to dividends. Moving on to our 2025 plan and guidance. If the primary objective in 2024 was to demonstrate the capital efficiency of our asset base and to generate annual free cash flow, then the core objective of our 2025 plan can be characterized as longer-term positioning, wider business building, and option aggregation. Beginning with our upstream business, we're showing a range of total full-year production growth of 9%-14%, with oil up 5%-8%. The total production growth rate is higher than the oil rate, as we should benefit from the full-year impact of increased gas processing in Texas, which leads to the gasier mix that John referenced. We've got a fairly broad range of D&C capex, partially to reflect some optionality and partially given some uncertainty on non-op activity. Full-year operated D&C capex is forecast to increase by about 9%, while non-op spend could be $10 million, up from essentially zero last year. We're currently seeing well costs maybe 2% to 3% higher than last year, but we're showing full-year upstream capex increasing by a higher percentage basis, including higher relative to production volume growth rates, primarily due to development being back-end weighted. For measurement purposes, the capex is fully captured in 2025, while a smaller percentage of production is captured within the year. Specifically, 45% of our net operated wells put online are scheduled for the fourth quarter, most of which are currently set for New Mexico. There's a scenario where we might accelerate the midstream project, and if it's operational by late in the year, this might allow us to flow into the new pipe and also collect some midstream revenue. Other aspects of upstream, including infrastructure outside of the gas midstream project, land, and other smaller items, are mostly in line with spending levels from 2024 on an accrual basis. Midstream spending ranges shown of $60 million-$80 million correspond to what we believe is a reasonable construction timing schedule, though it could be slower or faster. We plan to fund this with cash flow, cash on hand, and borrowings from our credit facility as needed. We forecast staying approximately neutral for the year on debt at about $70 WTI. We're fortunate to have our balance sheet in good shape should we choose to increase debt modestly during the build-out phase. I'll note that we explored the possibility of alternative financing for the midstream project, but have currently chosen to keep it simple on balance sheet with our low-cost revolver, as well with full equity ownership, while we can reconsider options as the project develops and as cash flow takes shape. For power, we show a tighter investing range of $18 million-$22 million. Recall, this is not capex at the Riley level, but rather a contribution to an equity method investment from Riley down to the joint venture after the benefit of project-level financing at the JV level and then net to each 50% JV partner. This year's spend is for funding the ERCOT project, and the team is making good progress there. We listed several updates on page 11 of our investor presentation. To summarize, we're trying to build complementary assets across upstream, midstream, and power that work well together. We're trying to turn challenges into opportunities, aiming to create situations that allow for multiple ways to win. For example, if our working interest in operated wells in New Mexico is lower than 100%, then we have a midstream asset to benefit. Note our average is about 60% working interest. If GORs increase over time on our New Mexico oil wells, then we have a midstream asset to benefit. If gas basis in the Permian stays materially negative, then we have lower-cost feedstock for power generation, leading to higher spark spreads for selling to ERCOT. Lastly, just for context, if gas index prices for the year stay somewhat elevated, yet basis remains tough, we still might realize an effective gas price of roughly $1 million-$2 million, which could correspond to $10 million-$20 million of revenue compared to negative $1.4 million last year. I'll turn it back to Bobby for closing. Thank you. Thank you, Philip. Once again, we appreciate your time and interest in Riley Permian. While we're pleased with our strong 2024 results, our focus remains firmly on the future. We are committed to building long-term value through disciplined capital allocation, strategic infrastructure investments, and operational excellence. Our recent initiatives position us for sustained growth, and we believe our long-term strategy will continue to drive shareholder value well beyond this upcoming year. Thank you for your continued support. Operator, you may now turn the call over for questions. At this time, I'd like to remind everyone in order to ask a question, simply press star, followed by the number one on your telephone keypad. We will pause for just a moment to compile the Q&A roster. Once again, that is star one for any questions. We'll pause for a moment to compile the Q&A roster. We're listening here. We'll take our first question from the line of Neal Dingmann with Truist Securities. Please go ahead. Morning. Thanks for the time. Philip, maybe first one, just on the power side, I'm wondering, you continue to ramp up, you've got the ERCOT project coming quite soon. I'm just wondering, could you tell us maybe on the heels of that, what are the things you would consider, maybe what type of upside? And then maybe just for my second, I love the potential for the midstream gas contract and just wonder besides the one that you've agreed for, what other upside could we see there? Thank you. Yeah. Thanks, Neal. Good morning. Yeah, power merchant project's going great. Really excited about it. Put some updates there on our slide and the investor deck. We've got all the thermal generation. It's a tight market out there, so we're excited to have procured all of that. We've got our sites for thermal. We've got several interconnection agreements. Those take a while. There's both power and gas. We're excited to have done that. Next steps will be construction. That'll start in the following quarter, maybe that last 90 days. Gas infrastructure, maybe that's a six- to nine-month build. Then we've got some power interconnect there, 30-day, maybe ERCOT decommissioning. We still think that's kind of a fourth-quarter deal. It might roll into the first part of next year, depending on how much testing we want to do. That's kind of the timing. As we noted, we are assessing battery still. It's been a volatile market, both on economics and then with some latest tariff developments and such. Just a quick thought there. Battery price, I guess first, battery generation that's been loaded to the grid has been very large. This is a bit like LED TVs, the pricing. You've got a ton of supply. Price has been falling. The margin's been falling as well, and so we're just continuing to assess how much we want to do there. Overall project, though, excited about it. Prices are looking good. We think this could be a nice business for next year. On the whole, it's relatively small for our total company. We like to think of it as like a hedge for natural gas basis. As long as natural gas basis out in the Permian is very poor, and even at these higher Henry Hub gas prices, you still get some nice spark spread. Neal, you know we report this as an equity method investment, so the financials are down below at the JV. They just trickle up to us in the form of that equity method. We've also got a project financing down there, which limits our need to have to invest true capital other than the equity we're showing there. That is kind of an overview. Happy to answer some more if helpful. I know you asked about midstream. I might let Bobby talk about midstream just to give you some exciting outlook there. Yeah, thanks, Philip. No, we're excited about as we develop our New Mexico assets to kind of gain control of our molecule as quickly as we can and make sure that we're not reliant on somebody else's takeaway capacity for us to develop. I think we're putting in a long-term plan to solve for infrastructure in New Mexico that includes gas, water, and power, which is what we did in Texas initially when we started there, and that's what led us to the efficiencies that we're able to operate in Texas with now. We expect to, after this year of getting all that stuff in place, to be able to really see some benefits in the future in New Mexico. That's just part of the business, is getting the molecules to market, and we're staying on top of it. Thank you, guys. Our next question will come from the line of Derrick Whitfield with Texas Capital. Please go ahead. Good morning, guys, and congrats on a strong end to 2024. Thank you. With my first question, I wanted to focus on the New Mexico gas midstream project. I certainly understand the need for the project. Could you perhaps speak to your decision to build it versus seek a solution from a midstream operator? Yeah, let me kind of dig into that. Because basically, when we looked at what our development potential would be with over 100 net locations and probably upwards of close to 200 gross locations, the choices that we had in the area were somewhat limited. The whole region is suffering from a lack of takeaway capacity, not only us, but some of the other operators in the area. Basically, building a one-off treating plant in New Mexico, a lot of difficult permitting regulations in the state right now, and a plant would have to be quite large to actually service what our long-term needs were. The option we opted for is just to move the molecule through a low-pressure gathering and compression into a high-pressure line that we're building roughly 56 mi, something along that neighborhood, to tie into a midstream company for treating and processing that. We're looped into about 12 different processing plants, so it will really create more efficiency for us with limited or no downtime. I think long-term, it's kind of a big pill to swallow initially, but I think you're going to see a lot of upside in that, not only from our production, but from other operators in the area. Yeah, let me add on one thing there, Derrick. Bobby gave you a little nugget for those paying attention. He said 100 net locations and 200 gross. What that tells you is our working interest is less than 100%. I think it's probably closer to 60-65% than 50%. Inherently, what that means is you've got, even for your produced or, sorry, for your operated molecule, you've got a fair amount of non-owned working interest in there. While we're not talking about fees and revenue for this midstream project just yet, know that we're going to charge a market rate, and there are other parties then benefiting that. Even if zero third-party producers shows up, we've got a fair amount there of non-owned working interest that can represent true incremental revenue. Terrific. Great color. Referencing slide six, and also thanks for the color on D&C optimization and your prepared remarks. Maybe referencing slide six, could you speak to how D&C cost per foot progressed throughout 2024? What's baked into your 2025 plan from the perspective of location mix, lateral length, and cost per foot? Yeah. 2024 was an excellent year. Again, we drilled predominantly in our Champions asset, worked our way into New Mexico, completed a couple of those wells that we're really excited about. We're probably 20 wells in, horizontal wells between us and our predecessor, and it really looks just as exciting as our Texas asset. From a cost per foot, we did continue to improve. Like we said, I think we were down 11%, if I have that number right. You've seen the slide. It's around $520 a foot, I think, for 2024. No, we've had to kind of strategically wait till we have our infrastructure fully figured out, which plan we were going to go with. That's why, again, we were kind of heavily in Champions upfront. In 2025, I think you'll see kind of the same strategy where we're picking our rig back up very soon and starting in Champions where we have infrastructure. Again, we've put that money in in prior years, which allows us the flexibility to spend our money there for development. Again, we'll be doing that same thing in 2025 once we get the infrastructure in place. We're putting our New Mexico drilling in the back half of the year. We'll have all of our compression and some of our short-term upgrades to be able to go to our current gatherer in place by the time we complete those wells. We're also doing some testing as we speak on some completions that we drilled late last year there in New Mexico. We think that'll give us some technical advantages as we start completing wells in the second half of 2025. That's kind of why we start in Champions and end in New Mexico for this year. Just to clarify on lateral length for 2025, you saw an improvement, I think, 20% longer in 2024. Would you project that to continue to lengthen? I think in Champions, we tend to have a setup where mile-and-a-half laterals are very feasible. In New Mexico, much of what we had of the permit-wise when we purchased, they're set up on one-mile units. We still think there's other places to save there, where half of the extra cost of New Mexico versus Texas is in stimulation. As I mentioned, we're already playing around with our recipe of increasing stage length and also looking at we are fracking with slick water in New Mexico and more of the gelled frack in Texas. We're already sampling what a cross-link frack can do in New Mexico, which could provide for some upside later. As we see the results of those tests right now, that has potential, at least, for savings in 2025. We'll see what the tests show. We're excited about the opportunity that could be significant. All right. Great update. Thanks for your time. Our next question comes from the line of John Wide with Riley Capital. Please go ahead. Good morning, and congratulations on very nice results all the way around, especially your approved reserve report. Thank you. I'm wondering if you could provide or talk about some more detail on your ERCOT effort, maybe give us an idea of how many deals are being worked on and what's the status of those deals, and when you think you might get something executed that you can announce. Yeah, John, good morning. This is Philip. What I'd say right now, we've got our project that we're deep in the middle of, the phase two, the first one of the ERCOT that we're doing. We like the market response so far. We appreciate people being supportive. We're intrigued about doing more. At the same time, you see the news and what's happening. Everybody's talking power for data centers and so forth. I'll tell you, we're exploring different ways we can participate in that. We've got a large amount of gas reserves. We're going to have increased control over some of our gas. So we're intrigued by the opportunity. We're grateful that we had a nice first-mover advantage. We do want to see how this works out to some degree, how we're progressing. Some of these updates came in just in the last week with some of our interconnection agreements. That's something, I'll be frank, those can take a while because realize these large gas midstream companies have been, if you've been listening to their earnings calls, some of them say they got 75 inbound solicitations, and they're working on all of these. It's very topical. That's exciting. Glad our industry is being both responsive and forward-thinking. I'd say hang tight, and let's see how it goes. We'll be back here in two months reporting on first quarter. Okay. Thanks for the update, and I'll turn it back to the operator. Our next question will come from the line of Noel Parks with Tuohy Brothers. Please go ahead. Good morning. Looking into the year, I'm assuming service availability or cost pressure are not a big concern in terms of the scenarios you've been looking at. Is that fair to say? Yes. I think we're doing really pretty well. The drilling side is neutral to slight improvement. There's been actually a really nice reduction through consolidation and more of the stimulation services. I think what we're experiencing there in New Mexico has been a good availability, and we've had some nice savings from, say, 2023. Just to add on to that, Noel, if there's any confusion, I've mentioned in my prepared remarks, we see well costs for the year slightly up. That's what we're modeling currently. Hopefully, that's conservative. Some of what that accounts for are some fixed costs, like facilities for some of these new areas that we're pushing into for our five well pads. It's got that fixed facility cost that somewhat offsets the benefits that John's describing on drilling and completion. Great. Thanks. You did mention just the statistic that you were using 20% more self-generated power than a year ago. Is that a good sort of plateau for where you think you'll be, or is there upside ahead you anticipate for that? Yeah. I think what we were doing is really taking our time to test this to ensure the high run rate and reliability. We're continuing to transfer overload. We've got more to do there. We've got plenty of room. We're excited to keep doing that. I think you'll see a little bit more there next time we're talking. All in all, that shouldn't translate to much change in our LOE. This is a small part of the overall company, but it's nice to say that we're doing that, and it's nice to have some ownership in that joint venture. Great. Thanks a lot. Again, for questions, press star one. Our next question comes from the line of Jeff Robertson with Water Tower Research. Please go ahead. Thank you. Good morning. On the midstream projects, can you talk a little bit more about timing of when you think it might come into service? Also, Philip, on the benefits you outlined, will those show up in financials as separate line items, or would they show up, for example, if you're marketing third-party gas for non-operators, would those be a reduction to your LOE? Yeah. This is John. I'll take the timing of the midstream. I think as we see it, it's kind of as early as possibly the end of 2025. Likely the longer case is somewhere in mid to end of first half, third quarter. It really comes down to about four different variables. It's the right-of-way, the regulatory approval of the route. Those are both kind of, I don't know, five to nine-month type things. They run in parallel. Afterwards, you have a decision to roll the pipe for, again, the long pipeline that Bobby described. Ultimately, it's the execution. The execution of it is the most obvious. Timing-wise, very little extra play there. It really comes down to the right-of-way and the regulatory approval. We think we've got a good jump on those of getting a final route approved, being able to get that little bit earlier order in on the pipe. We're excited about it. We would like to see this go as quick as possible. Right-of-way and regulatory are the cheapest parts of the whole process. You can see what a dilemma that is for us to forecast exactly how that fits into 2025 or 2026 when the bigger expenses of the pipe and actually the manpower to get it laid. Those are kind of some of the key triggers of when that money will be spent. Jeff, on the income statement geography, we're still working through it, but I think at a high level, you'll see some midstream revenue. You may see midstream OpEx, and then you'll see an intercompany elimination to adjust out from the gross to the net for our owned working interest versus the gross that I described before. Reminder, you can think about it as the gross as it starts. You can jump on and varice and look at how much gas we produce out there on a gross basis and probably do some simple math as to what some market rates could be and think about how that has the potential to grow into the future. Philip, I think you said that production in New Mexico would be fourth quarter weighted for 2025. Is some of that dependent on progression on the midstream system? Yeah, absolutely. It is. Really, it kind of depends when we get that done, whether it's even if it's late fourth quarter, I think we'll be lucky to be getting much production through there other than as it does turn on, there'll be some immediate impact that we'll be able to turn on of existing assets. From newly drilled completions, that's what the wells in the second half, they'll either come on fourth quarter or probably first quarter of 2026. Just to add to that, I think there's two lenses you can consider. The physical constraint for the flow assurance is what John just addressed. It gives us higher confidence to produce those if we're going through our own system. But then there's also the opportunity, right, or opportunity cost if you don't put it through your own system. So all else equal, if we're going to be doing these, we'd rather put it through our own system and collect some of the fee revenue. Yeah. There are some other phases of the project where we are laying some gathering system into this New Mexico asset, part of what we've already described. That will bring on some other production that already exists, again, besides just what we'll be drilling. Lastly, on the midstream, does that footprint give you any advantages in the acquisition market of assets that could further support the build-out? That's pretty perceptive. Exactly what we're thinking. Thank you. That will conclude the question and answer session and our call today. Thank you all for joining. You may now disconnect. Welcome to Riley Exploration Permian's quarterly conference call. We appreciate you joining us today.