Earnings Call Transcript - REPX Q3 2025

Operator, Operator

Ladies and gentlemen, thank you for being here. Hello, my name is Dustin, and I will be your conference operator today. I would like to welcome you to Riley Exploration Permian Inc.'s Third Quarter 2025 Earnings Conference Call. I will now pass the call to our CFO, Philip Riley. Please proceed, sir.

Philip Riley, CFO

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, CEO

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 nine months, we 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, COO

Thank you, Bobby, and good morning. Riley Permian has once again shown its commitment to safe operations, achieving a total recordable incident rate of zero 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 five and turned in line ten gross operated wells. Five of those wells turned in line were completed at the end of the second quarter. Average daily net production was 18,400 barrels of oil 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 two 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 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, CFO

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 two 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 two 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 nine 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 nine-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 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 two completions from 2026 into the current quarter. These wells will support 2026 production with no impact on 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, CEO

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

And we will take our first question from Derrick Whitfield from Texas Capital.

Derrick Whitfield, Analyst

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 three segments of your business while maintaining control of each?

Philip Riley, CFO

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 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 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 in 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 maybe 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, Analyst

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, CFO

Sure, I can begin and then perhaps John can add some details about the volumes. Regarding netbacks, it's not a straightforward situation. We prioritize flow assurance, and we are implementing advanced systems with newer generation gathering compression pipelines and facilities. We anticipate some economic improvement due to more efficient, high-quality processing and treatment facilities. We have some projections in place that we hope to achieve. Additionally, improving netbacks may involve committing further to attain capacity, which essentially means securing access to capacity that connects to the Gulf Coast. Some companies have made such commitments to midstream partners for that capacity, allowing them to benefit from prices closer to ship channel rates. Negotiation is a key factor here, and not all companies can execute this strategy since many in the Permian would prefer ship channel pricing over Waha pricing. However, we believe there is a range of possibilities, and we aim to move some of our gas closer to that, though it will take time.

John Suter, COO

From an operational perspective, this midstream project is essential for our company to grow the New Mexico asset. By investing an additional $15 million, we expect to achieve better processing outcomes from the new provider. The current provider can only manage so much, and without gas decline, there will be no further capacity. This new line will give us an additional capacity of $150 million to $200 million, enabling us to focus on our primary objective of drilling oil and gas wells and ensuring we have a destination for our product. Currently, our progress in New Mexico is limited due to this capacity issue. With the new capacity, we will be able to respond to fluctuations in commodity prices and increase our production of oil and gas as needed.

Jeffrey Robertson, Analyst

Bobby, to follow up on your last comment, once the midstream project is completed, it will enable Riley to produce more oil because we can develop the field at our own pace based on commodity prices, as that is where the real value currently lies. Is that the correct way to look at it?

Bobby Riley, CEO

Absolutely. I believe that was John speaking, and he is correct. Our goal is to achieve unrestricted takeaway capacity for gas, oil, and water, which will provide us with complete flexibility in our development pace for the asset. We have been drilling on some pad locations with three to five wells coming online simultaneously, leading to a significant increase in the mix of commodities all at once. Our current strategy is aimed at positioning ourselves with all options available.

Philip Riley, CFO

Yes, I believe this ties into my earlier comments regarding maintenance scenarios and spending levels. At the start of 2025, we disclosed spending around $130 million on our midstream project to complete the pipeline in our main development area. Since acquiring Silverback, we have the option to expand that further, but it isn't urgent. We're evaluating various options, and if prices remain around the $60 mark or slightly lower, we'll keep an eye on pricing and cash flow. We can maintain the current position and keep this on the balance sheet. Based on my earlier scenarios, we could be free cash flow positive after accounting for combined upstream and midstream capital expenditures, estimated at about $170 million to $180 million, possibly just under that after dividends at a $60 WTI price. While there may be a small deficit, there's significant capacity available because we are creating value. We feel secure knowing we have built real asset value, with an estimated $120 million to $130 million in midstream spending by then. Consequently, we are also exploring financing options at the project level. We’ve discussed using a credit facility, which currently doesn’t assign any value to our midstream assets, focusing solely on upstream reserves. However, there is significant hard asset value to consider. By the end of next year, if we move forward, this could amount to a book value of $120 million to $130 million. We are also contemplating bringing on an investment partner in various forms. We are actively working through these options, and we are confident we have several alternatives available. No definitive decisions have been made at this time.

Jeffrey Robertson, Analyst

So if you went some sort of project route, any economic benefit from third-party volumes would flow through that type of entity. Is that right?

Philip Riley, CFO

Yes, I'm referring specifically to capital partners, Jeff. We could potentially involve third-party operators who might acquire some capacity from us, which would allow us to collect additional fees. This is a possibility that could enhance our revenue and cash flow over time, although it wouldn't address the initial capital required for project development. There are advantages and disadvantages to consider. The advantage is that we'd generate true incremental revenue from third parties. However, with Silverback and the expansion of our footprint, we believe we can eventually fill our entire capacity independently. This could take around 7 or 8 years. So, the question becomes whether to sell some capacity for the short term or a longer term at a higher price, or to further expand our operations. It's an organic process that we're currently navigating. Regarding the capital, we are considering various types of partners, whether through equity or credit arrangements.

John Suter, COO

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.

Nicholas Pope, Analyst

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, CFO

I think this quarter, workover expenses were probably $3 million, or about $2 million to $3 million, higher than usual. This expense is always present; it can depend on our wells compared to shale, but we consistently perform workovers. Last quarter was relatively light, and this quarter we increased our efforts. You can see this increase reflected in lease operating expenses. Overall, I believe our total workover costs were around $8 million to $9 million, which means they were likely $2 million to $3 million higher than the previous quarter.

John Suter, COO

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 two 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, CFO

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 down, and it's a big miss. But proactive is 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, Analyst

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, COO

Yes. We are currently in Texas with plans to complete 8 to 10 wells by year-end. This will help replenish our inventory of DUCs, providing us with flexibility during the commodity price fluctuations. We will be able to frack these wells as needed throughout the year based on favorable market conditions. Towards the end of the year, we will redirect our attention to New Mexico and initiate a drilling program there. In the past 1.5 years, we have only drilled 12 wells in New Mexico, but we’ve achieved excellent results so far, and I’m eager to explore more opportunities in that area.

Philip Riley, CFO

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 mid-year. 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 or slower around the mid-year.

Noel Parks, Analyst

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, CFO

Sure. Let me address the first part of your question, which I believe was about the uncertain macro and economic situation. I acknowledge that the upstream energy industry is currently out of favor. The equity markets face challenges, but the credit markets, both for upstream and in general, are quite healthy right now. Regarding upstream, there has been significant consolidation, leading to a reduction in bank paper and an increase in lending. The high-yield and bond markets are also open, particularly in upstream, where we see very low spreads. While that’s not the primary focus, it provides some context. Additionally, there's a strong appetite for capital in engaging new projects, especially infrastructure. For instance, looking at what's happening with hyperscalers, AI, and data centers, there's an immense amount of capital being deployed there. Midstream infrastructure assets tend to be more easily financed compared to upstream. We have significant hard asset value, with contracted volumes and values that can serve as collateral for lending. Currently, our credit facility does not have any allocated value for that, indicating potential debt capacity. As an example, our joint venture partner, RPC Power, has a straightforward credit facility from a traditional bank for financing, with a cost of capital around 7% to 8%. Such terms could also be available for midstream projects. If we seek additional capital, we could consider bringing in private capital investors through common or preferred equity structures at the midstream level. There are case studies of various groups that have engaged private capital in such projects, and there is enthusiasm from private capital providers for these opportunities. I anticipate receiving interest after this conversation regarding these options. Pure common equity is also an avenue if we wanted a significant investment. I hope that clarifies things.

Noel Parks, Analyst

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 anywhere at any time, 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, CFO

We feel fortunate to have started this nearly three years ago, especially since the environment has changed significantly since then, both nationally and in West Texas. While it's validating to see our initial thesis hold true, the ultimate goal is to generate profits. Regarding new projects, we're taking a measured approach. Although we have a busy agenda, we're continuously seeking new investment opportunities where we can achieve good returns. With increasing competition in the data center space, we want to ensure we can add incremental value. Additionally, as more players enter the market, it often leads to lower returns, so we must be confident that we can achieve a satisfactory return on our capital. When considering whether to engage in a new project, we also evaluate if we would prefer to develop it to a critical stage and sell it or retain it on our balance sheet long-term. If we opt for the latter, we would need to believe that we would receive a re-rating, allowing us to trade at a higher valuation, as opposed to the typically lower multiples associated with upstream companies compared to those in infrastructure or independent power production, which trade at higher EBITDA multiples.

Operator, 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.