Evolution Petroleum Corporation (EPM) Q4 2026 Earnings Report, Transcript and Summary

Good morning, and welcome to the Evolution Petroleum Fourth Quarter and Fiscal Year 2026 Earnings Release Conference Call. [Operator Instructions] Also note, today's event is being recorded. At this time, I would like to turn the conference over to Brandi Hudson, Director of Investor Relations. Please go ahead.

Thank you. Welcome to Evolution Petroleum's Fiscal Q4 2026 Earnings Call. I'm joined today by Kelly Loyd, President and Chief Executive Officer; Mark Bunch, Chief Operating Officer; and Ryan Stash, Senior Vice President, Chief Financial Officer and Treasurer. We released our fiscal fourth quarter and full year 2026 financial results after the market closed yesterday. Please refer to our earnings press release for additional information containing these results. You can access our earnings release in the Investors section of our website. Please note that any statements and information provided in today's call speak only as of today's date, September 16, and any time-sensitive information may not be accurate at a later date. Our discussion today will contain forward-looking statements of management's beliefs and assumptions based on currently available information. These forward-looking statements are subject to the risks, assumptions and uncertainties as described in our SEC filings. Actual results may differ materially from those expected. We undertake no obligation to update any forward-looking statements. During today's call, we may discuss certain non-GAAP financial measures, including adjusted EBITDA and adjusted net income. Reconciliations to the most directly comparable GAAP measures are included in our earnings release. Kelly will begin with opening remarks, followed by Mark with an operational update, and then Ryan will review the financial results. After our prepared comments, the management team will open the call for questions. As a reminder, this conference call is being recorded. If you wish to listen to a webcast replay of today's call, it will be available on the Investors section of our website. With that, I will turn the call over to Kelly.

Thank you, Brandi, and good morning, everyone. As we look back at fiscal 2026, I want to put the year into perspective and talk about what we are building at Evolution. Over the past several years, we have deliberately broadened the business across assets, commodities and operating partners. Those investments are shaping Evolution into a more diversified energy company with multiple complementary engines, our legacy long-life non-operated producing assets, meaningful working interest positions across several proved undeveloped and longer-term opportunities and our growing mineral and royalty portfolio. Throughout that process, we have focused on the durability of cash flow and how much capital must go back into the assets to sustain them. Getting that balance right allows us to return cash to shareholders while continuing to invest in the future of the company. Our objective is to build greater value per share from across the entire portfolio. This year, we made considerable progress toward that objective. Our minerals and royalty portfolio became a more important part of the business. We continued investing selectively in our working interest assets, and we maintained our commitment to returning cash to shareholders. We also finished the year with a meaningful improvement in performance in the fourth quarter, providing solid momentum as we enter into fiscal 2027. The fourth quarter deserves particular attention because it demonstrated the recovery that we told you to expect on our last call. Many of the temporary items that weighed on third quarter results rolled off. Production increased and operating cost per barrel improved. Together with stronger oil and NGL realizations, those improvements drove a 20% sequential increase in revenue and more than doubled adjusted EBITDA. We achieved that recovery even as natural gas pricing remained a headwind. What stands out to me is the portfolio's ability to absorb that pressure with stronger liquids pricing and improved operations across several properties, helping offset that weakness in gas. This resilience reflects the deliberate work we have done to diversify Evolution's sources of production and cash flow. This quarter also brought the reversal in unrealized hedge losses that we highlighted in May. Ryan will walk through the financial impact, but my broader point from our last call remains the same. Higher prices on the production we are selling is a good thing. We hedge a portion of our production to protect cash flow and support our capital commitments while retaining exposure to higher prices on our unhedged volumes. In Q4, our realized oil price before hedge settlements increased 49% year-over-year to $90.74 per barrel, while our entirely unhedged NGLs realized $32.49 per barrel, up 27%. Hedge settlements offset part of the oil price benefit, but our unhedged production allowed us to participate in the stronger market. That is the balance we seek between protecting cash flow and preserving upside for shareholders. Looking at the full year, we dealt with operating interruptions and periods of unfavorable regional pricing, and those challenges affected our financial results. At the same time, average production was 7,077 BOE per day, slightly above 7,074 BOE per day in fiscal 2025 as acquisitions and development activity helped offset natural declines in downtime. Underpinning that stability is the continued renewal of our asset base. We produced approximately 2.6 million barrels of oil equivalent during the year and ended up with 27.2 million barrels of oil equivalent proved reserves, slightly above where we started. For a company like ours with a strong commitment to issuing dividends, maintaining that reserve base remains an essential part of the job. That brings me to our minerals and royalty strategy and the role we expect it to play in Evolution's next stage of growth. Subsequent to the end of the fiscal year, we took another step in building our mineral and royalty business with our approximately $16 million acquisition in the core of the Permian/Midland Basin. The transaction added approximately 3,420 net royalty acres and over 200 BOE per day of current production across Reagan, Upton, Glasscock, Midland and Martin Counties in Texas. It increases our exposure to high-margin current production as operators in one of the country's most active basins continue to develop the acreage, the acquisition also provides CapEx-free upside to both near-term and long-term field level production growth. We believe this is the kind of investment that can strengthen Evolution's earning power over time. As operators develop additional wells, we benefit from new production and cash flow without funding the drilling and completion costs ourselves. Building on the positions we established in the SCOOP/STACK and Louisiana during fiscal 2026, the Permian Minerals acquisition adds another durable capital-light source of growth and cash flow generation. With respect to our working interest assets, we believe they will continue to provide an established production base and opportunities to create value through workovers, production enhancements and selective development. Alongside those assets, a growing royalty contribution gives us a better balance between cash flow that requires ongoing reinvestment and cash flow that benefits from development funded by others. We believe that combination strengthens our ability to sustain shareholder returns across commodity cycles. The next step is for the investments we have made to contribute more fully. That will build as operators bring additional wells online in fiscal 2027. We are encouraged by the activity underway in Oklahoma and Louisiana, and we will be watching that progress closely as we move through the year. Mark will provide more details on the development activity across the portfolio. A quick word on how we see the market from here. On oil, our outlook for demand remains steady as she goes, and the fourth quarter showed how stronger prices can benefit our cash generation. On natural gas, we continue to see a constructive longer-term demand outlook as LNG export capacity expands and power demand grows, including from data centers. The challenge for us has been translating that broader demand picture into prices at the field level, where regional differentials have weighed on realizations. As those differentials normalize, we expect better pricing across our affected gas assets, providing another potential source of improvement in the next few quarters. As we look forward to fiscal 2027, our capital allocation strategy is unchanged. We will continue to capture the contribution from the investments we have already made, work with our operating partners to maintain reliable base production and direct additional capital toward opportunities with the most attractive returns. At the same time, we will continue evaluating acquisitions with the same discipline, including how they are financed and what they mean for existing shareholders. Our dividend remains central to those decisions. The Board's latest declaration maintains the quarterly dividend at $0.12 per share for fiscal Q1 2027 and will mark our 52nd consecutive quarterly payment. Since December 2013, we have returned approximately $151.7 million or $4.53 per share to shareholders in common stock dividends. As I've said before, we set the dividend at a level that we believe can be sustained for multiple years given our strong outlook and the diversified platform we are building. We enter fiscal 2027 with a broader portfolio and more opportunities to build on that record. Our focus is now on translating the investments we have made into stronger cash generation while maintaining the balance sheet and capital discipline that underpin long-term value per share. With that, I'll turn the call over to Mark.

Thanks, Kelly. Good morning, everyone. I'll focus my remarks on key operational highlights from the quarter and on what we see across the portfolio heading into fiscal 2027. I encourage the listeners to review our earnings press release and filings for additional details across our asset base. Overall, operating performance improved during the fourth quarter as several of the issues we described in May rolled off as expected and contributions from our recent investments continue to build. Turning to individual assets. At SCOOP/STACK, which was a clear bright spot for the year, fiscal Q4 production averaged 1,275 BOE per day, up approximately 14% from the prior year quarter, while per unit lease operating costs declined to $10.33 per BOE from $11.05. That combination, production up, unit cost down reflects the growing contribution from our mineral and royalty interest layered on top of the working interest base. Third-party operators remain active around our acreage. Across our combined SCOOP/STACK portfolio, operators brought online 31 gross wells during fiscal 2026. As of July 31, our interests have grown to 725 gross producing wells, 36 gross proved undeveloped locations or in various stages of drilling and completion and more than 360 additional gross locations. During the fourth quarter, we also divested noncore nonproducing SCOOP/STACK mineral acreage for approximately $3.1 million, enabling us to monetize longer-dated development opportunities while retaining acreage with near-term cash flow potential. In Louisiana, operator activity across our Haynesville and Bossier positions continues to progress, with wells moving through drilling and completion and into production. We continue to add to this position through bolt-on acquisitions, and we expect the contribution from these royalty assets to keep building through fiscal 2027 and beyond as operator development activity converts our inventory of locations into producing wells. As of July 31, the portfolio included approximately 90 gross producing wells, 16 wells in various stages of drilling and completion, 35 pre-permitted wells and over 60 additional gross locations. At Chaveroo, full year production increased meaningfully, averaging approximately 260 BOE per day in fiscal 2026 compared to approximately 175 BOE per day in fiscal 2025, reflecting the full year contribution from wells previously brought online. Fourth quarter production was lower year-over-year, but this comparison really just reflects the initial flush production from new wells brought online in fiscal Q4 2025. We also completed the rod pump conversion program discussed on our last call, with all 7 producing wells converted by June 30. Looking ahead, we have permits in hand for the next 6-well development program and are working with our partner to determine the timing of drilling. At TexMex, operating performance began to improve during the fourth quarter as the extensive workover program progressed. The program was not completed until July, and we expect production to continue increasing and operating expenses to normalize going forward. The operator continues to identify opportunities to restore and enhance production from the existing well base. And we expect the TexMex assets to remain an important and growing contributor to cash flow in fiscal 2027 and beyond as those efforts continue. Across our legacy assets, Delhi, Jonah, Barnett, Williston and Hamilton Dome, the focus remains on maintaining base production, improving operating reliability and pursuing selective workover opportunities rather than deploying significant new development capital. Operational issues that affected several of those properties earlier in fiscal 2026 improved as the year advanced. At Jonah, regional gas differentials have improved meaningfully. That improvement should support better realizations from our West Coast exposed gas as we move into fiscal 2027. With that, I'll turn it over to Ryan.

Thank you, Mark, and good morning, everyone. As Brandi mentioned earlier, we issued our earnings release yesterday, which contains more information on our results. For today, I'd like to go through our fiscal fourth quarter financial highlights. In fiscal Q4, production averaged 6,901 BOE per day, up 3% sequentially and down 4% year-over-year. The lower year-over-year production was due to flush production associated with new wells that came online in Chaveroo, along with natural declines in our other fields. Total revenues were $24.2 million, up 20% sequentially and 15% year-over-year. The sequential improvement reflected higher realized oil and NGL prices, increased production and the roll-off of the prior period transportation adjustment at Delhi. Compared to the year ago quarter, average realized prices before hedge settlements increased 20%, more than offsetting the decline in production. Net income for the quarter was $4.6 million or $0.13 per diluted share compared to a net loss of $8.9 million in fiscal Q3 and net income of $3.4 million or $0.10 per diluted share in the year ago period. As Kelly discussed, the quarter included a $5.8 million unrealized gain on derivative contracts compared to a $7.6 million unrealized loss in fiscal Q3. Excluding selected items, adjusted net loss narrowed to $0.6 million from $2.9 million sequentially compared to adjusted net income of $1.1 million a year ago. Adjusted EBITDA more than doubled sequentially to $6.5 million from $3.1 million, reflecting stronger oil and NGL pricing across the portfolio, the cessation of winter weather impacts, contributions from our recently acquired Louisiana royalties and improved performance at Delhi, where production increased and operating costs declined. Those improvements helped offset continued weakness in natural gas realizations, particularly at Jonah. Compared to the prior year quarter, adjusted EBITDA declined from $8.6 million, primarily due to benefits received in the prior year period in our Barnett Shale asset as a result of the joint venture audit. Lease operating costs increased to $12.8 million compared to $11.4 million in the year ago quarter. As I just mentioned, the prior year period included a $1.9 million credit from the operator of our Barnett Shale properties related to a joint venture audit. On a per unit basis, after adjusting the prior year period for that credit, LOE was $20.35 per BOE compared to $20.25 per BOE a year ago. LOE per BOE improved approximately 5% sequentially from $21.49 in fiscal Q3. On the hedging front, we have continued to add hedges to comply with our credit facility covenants. Our ongoing goal remains to reduce downside commodity price risk and protect cash flow for our shareholder return strategy while preserving the maximum potential upside. This strategy can result in realized and unrealized losses on our hedges in some periods, but benefit us in other periods and will provide more predictable and stable cash flows over time. Turning to the balance sheet. Cash on hand totaled $6.1 million at June 30, up from $2.6 million at March 31. Borrowings under our credit facility remained unchanged during the quarter at $56.5 million with $0.8 million in letters of credit outstanding and a weighted average interest rate of 6.69%. Total liquidity at June 30, including cash and available borrowing capacity, was approximately $13.9 million. We generated $6.8 million in operating cash flow during the quarter compared to $3.5 million in fiscal Q3. Capital expenditures were $1.4 million, and we invested an additional $1.7 million in mineral acquisitions. We also received approximately $3.1 million from the sale of noncore SCOOP/STACK mineral acreage, as Mark mentioned earlier, and $1 million of net proceeds from shares sold under our at-the-market program. For the full year, operating cash flow was $23.6 million compared to $33.1 million in fiscal 2025, with the decline primarily reflecting working capital movements. Subsequent to quarter end, we completed the Permian/Midland Basin Minerals acquisition using proceeds from our common stock offering and borrowings under the credit facility. Following those transactions, as of August 20, total liquidity was approximately $19 million. That liquidity includes a temporary increase in our borrowing base from $65 million to $73 million, effective through October 20, unless redetermined earlier. We currently anticipate our fall borrowing base redetermination to occur on or about October 1. During the quarter, we paid $4.3 million in common stock dividends, bringing total dividend payments for fiscal 2026 to $16.9 million. The Board has declared a quarterly dividend of $0.12 per share for fiscal Q1 2027 payable September 30 to shareholders of record on September 21, marking our 52nd consecutive quarterly payment. As we move into fiscal 2027, our financial priorities remain focused on maintaining liquidity to execute on our strategic growth plans while managing leverage and deploying capital where we expect attractive returns per share. The improvements in fourth quarter cash generation and the growing contribution from our recent investments support our ability to pursue those opportunities while continuing to return capital to shareholders. I'll now hand it back over to Kelly for closing comments.

Thanks, Ryan. To sum it up, fiscal 2026 tested our portfolio and the portfolio passed. We navigated operating disruptions and pricing headwinds, held annual production steady, replaced the reserves we produced and maintained our dividend. We also continued investing in the business and delivered much of the fourth quarter recovery that we had anticipated. Looking ahead, we have a lot to be excited about. Development across our working interest and royalty positions, together with the Permian Minerals acquisition gives us opportunities to strengthen cash generation in fiscal 2027. We put capital to work, and we look forward to seeing those investments begin to fully contribute in the coming year and beyond. With that, I'll turn it over to the operator to begin the Q&A session. Thank you all very much.

[Operator Instructions] The first question will come from Jeff Grampp with Northland Capital Markets.

Maybe for Ryan, on the borrowing base increase, can you explain the dynamics there with it being temporary? What necessitated that given it sounds like you're only a couple of weeks away from getting a more formal redetermination process. Just want to kind of understand the mechanics and process there.

Yes. So Jeff, I appreciate it. It was -- honestly, it was part of our liquidity plan for the acquisition, too. I mean, obviously, we wanted to do the deal. We wanted to have flexibility to fund it either way. MidFirst was able to look at the borrowing base and give us an additional amount for the interim period until they actually redetermine the entire borrowing base. So it was really just to provide us additional liquidity and flexibility really for the acquisition because that increase was tied to kind of the amount of the acquisition.

Got you. Okay. That's super helpful. And then for my follow-up, just, I guess, kind of bigger picture across the asset base, given, obviously, the oil market changes week to week, but any signs of increased activity across the asset base as a result of the price appreciation? I mean, it looks like you guys have some permits or maybe considering with the operator Chaveroo some new drills. Is that an area that could see some increased capital allocation in the upcoming fiscal year? Or any other areas worth noting across the asset base would be interesting.

Jeff, yes, this is Kelly. So I'll let Ryan speak to a couple of the areas. But with Chaveroo, I mean I'll say that we are very much interested in moving forward with drilling, and we're just working with the operator on timing for those. So more news to come on that as we get further down the line with timing.

Yes. And then on the Permian minerals, we obviously are watching it pretty closely. I think we said maybe 7 rigs were running the last time that's actually ticked up 1 to 8 rigs running right now, and we've seen kind of steady permitting activity among the bigger operators. Obviously, Exxon, as we've mentioned, being the largest, they're continuing to add permits and like they're running about 5 rigs right now throughout our acreage. Double Eagle has been drilling pretty actively here recently. And actually, in the last, call it, 2 or 3 weeks, we saw Apache file probably about a dozen permits in Upton County. So hopefully, they'll get working on that piece, too. So obviously, the activity level we've been pleased with.

And then to follow up on the Haynesville, we continue to see some nice activity there as well, and we're converting wells into PDP there.

The next question will come from Nicholas Pope with ROTH Capital.

Kind of a good segue from the last question. You were just talking about Haynesville. You've seen some of these smaller acquisitions on the royalty side that you all have done here over the last year. Curious what the opportunity set might look like, what that -- maybe even broader than that, too, like looking at what the potential kind of this ground game type leasing and purchasing of minerals you all have been doing, what that landscape looks like, what you all think about the opportunity set right now?

Yes. Perfect, Nick. We still think -- again, this is -- these are neat deals. They're interesting, and they are deals that are not marketed, right? They're sort of scrapped together from the ground up. And we're still seeing opportunities there. We're excited about the prospects of those going forward. Now are you going to have some beautifully polished large chunky thing? Maybe, right? But those tend to get sort of competed over and bid for and all that. And if we can find one like we did in the Permian, where it's really just negotiated transaction where all parties are happy, then absolutely, we'd be interested in that. But for now, the sort of onesies and twosies that we're picking up and we're seeing convert sort of, frankly, ahead of our schedule when we got them we do think there's opportunities to keep going there, and we're excited about continuing to work with our partners on finding more of those. So and then -- sorry, Nick, just one more thing. I neglected to mention the SCOOP/STACK. Listen, the activity in that part of the world is up. I mean, I think it's about 8 years -- excuse me, 8 more rigs year-over-year this year versus last year. And so we're seeing some nice activity there. We're having our minerals and royalties there start to convert into more wells being drilled, and we're excited about some of the opportunities we're seeing on the working interest side there as well. So...

That's great, Kelly. I'm curious, I mean, it seems like there's a fair amount of bigger activity operator changes in the Mid-Con. I mean, are you all seeing that on the operator side, like changing hands? And I guess how does that -- how might that affect kind of the viewpoint if some of these assets change hands and bigger transactions?

So we have seen -- this is Kelly again. We have definitely seen some consolidation. And just -- I don't know, sort of anecdotally, if you buy a new toy, you kind of want to play with it, right? So these guys that are taking over assets have some really good locations to drill, and we're starting to see some activity there. Mark?

Yes. We've had a lot of activity and look up there with -- across all the operators. It's -- so we're expecting like at higher prices that it's even going to -- it's going to get better. I mean -- and they'll just shift into more of the oily area of the window on the SCOOP/STACK.

And... Look, bigger companies with bigger balance sheets, we certainly aren't complaining about that, more of a chance to put capital to work. And like I said, those are small, right? 2% to 4% working interest kind of stuff fits very well within our CapEx plans. And then obviously, the mineral side, please drill away.

Got it. And I know you haven't really given guidance. I know it's a difficult thing looking at kind of with the non-op acreage and royalties. But as you look at CapEx, any idea where things might be heading kind of on a run rate basis right now? It seems like things have been very moderate in terms of CapEx spend in the last several quarters, last year. I'm curious if you all have any visibility on what that might look like over the next year.

I mean, so we put out our budget, Nick, kind of another kind of $4 million to $6 million is what we put kind of for fiscal '27. Now we'll say that, that doesn't yet include any CapEx potential in Chaveroo. And as Kelly mentioned, we're kind of working with PEDEVCO there to figure out the timing on that, so the budget could change. We have assumed some activity in SCOOP/STACK with that $4 million to $6 million, but it could certainly accelerate more than we thought. And in fact, I think we actually have -- we do have quite a bit of capital already, I think, in AFEs in the SCOOP/STACK area that has been nice to see. And that budget does include that. So really, the big swing is probably going to be mostly in Chaveroo on the timing for those wells.

Okay, got it. I Appreciate it, I appreciate the time.

Yes. And not just the time, but also the amount, right? Is it going to be 3 wells? Not sure, but yes.

The next question will come from Jeff Robertson with Water Tower Research.

Kelly, you showed in the August slide deck slide showing that pro forma cash flow from royalty and mineral interest would have been about 20% of first 9 months fiscal '26 cash flow. Do you have a goal in mind of how big you would like to see that side of the business get? Or is it all opportunistic in terms of incremental capital versus royalties and non-op working interest?

So yes, I mean, that's a very good question. I would say, look, ideally, sure, you want that to be a bigger piece because they're -- they trade anywhere from rule of thumb. And when we run the numbers on it, they're kind of worth anywhere depending on the commodity, depending on how much drilling gets done, but 2 to 4-plus times on a per barrel or per BOE basis. So if you can buy those or continue to acquire those at multiples that are similar to what you could acquire or drill on with working interest stuff, then you want that to go higher. However, we still see some very, very nice returns on some of the working interest stuff. So I would say the answer is it's going to be opportunistic for now for sure, as we keep seeing deals that are highly accretive, we're going to put capital to that.

To be clear, Kelly, your approach to the mineral business is on minerals that are currently or will be producing soon as evidenced by the noncore SCOOP/STACK sale as opposed to just warehousing royalty interest. Is that the right way to think about it?

Absolutely, right. And that was an interesting one. So when we made our SCOOP/STACK minerals acquisition, what, a little over a year ago now, we put value on the PDP and on a number of locations that we felt might be drilled in the relatively near future. And we had a bunch of other acreage that I do think has a chance to be very attractive for somebody else with a longer-term horizon. But the ability to high grade that, right, put that money back into something that will be more accretive near term is something that's always out there and happy to move dollars forward on similar multiples. So...

And if I could ask 2 quick questions for Mark. Do you have a number in mind for an AFE for a Chaveroo development well in this environment, Mark?

Yes. Yes, the ones we're running with right now, and this is a preliminary number. It's about $3.6 million to $3.9 million.

And then secondly, Mark, it's been hot in North Texas since the end of July. Are you seeing any impacts on production in the Barnett Shale?

No. Actually, everything seems to be running quite well.

The next question will come from Poe Fratt with Alliance Global Partners.

Kelly, you mentioned that you put out some guidance for CapEx. Have you put out guidance for production and -- or I'm sorry, LOE for 2027?

No, Poe. And that's -- I could say we'd kind of like to. To be frank, we're being non-op and now non-op in mineral and royalty, we just don't often get enough visibility that we'd be able to put something out we'd be comfortable with. So...

Just to sort of frame it, though, when you look at the fourth quarter run rate, you're going to have Midland come on, you're going to have more activity with SCOOP/STACK. TexMex is still improving. Chaveroo is sort of a wildcard because of what's going on with PEDEVCO, right? And then the other ones are sort of in maintenance mode, right? Is that sort of a good way to frame it?

Yes. I think that's a decent way to frame it. And so the conclusion from what you just said is we're excited about '27. We think we're going to see with a bigger contribution from the mineral side with improvements along the way at TexMex and some of the other initiatives we have. We're excited about the opportunity, and we believe we ought to start seeing even better margins as we move forward or at least even better lifting costs as we move forward. We can't control price, right?

Yes. I mean -- I would just add, I mean, you saw in the fourth quarter, we are like right around $20 per BOE, right, for the whole asset. So we would -- as Kelly mentioned, we would think that would go down a little bit over time, like as minerals is contributing more.

Understood. And then can we just -- looking at what you did in the March quarter, you had mentioned in the last call, just a couple of issues, and I'd like to just clarify a couple of those. One, on SCOOP/STACK, you said that you talked about catching up on some of the data just because on the non-op wells. And are you current on that data? Is the fourth quarter a good run rate or base rate? Or do you still need time to catch up on some of the data there?

Well, that's an interesting question. And I think the thing -- as wells get put on in Oklahoma, in particular, they have -- it's a multi-month period before you actually necessarily know anything. So I would say we're caught up on the stuff we knew then, but we've had more wells convert. And so we're always going to be sort of chasing data on some of that stuff as we go.

Yes. I would say, in general, we probably have a better feel for what's coming online in the working interest side, right, because we actually have to get AFE. So we're able to see kind of when that's coming on. But on the minerals side, we're obviously just looking on public data sources, and we don't always have the best intelligence on when wells would come on. And to Kelly's point, they don't -- the operators don't have to put us and pay immediately. And so on the mineral side, we may see a bit more lag as far as production that we get to accrue versus when it comes on.

But I thought I heard you say before that you're encouraged by signs that activity is picking up on the minerals side in SCOOP/STACK.

Yes. I think that's a true statement. And look, when you just look at where rigs are, where our acreage is and all that, yes, absolutely.

And then on Delhi, you talked about the surprise that you got with the transportation contract. Any comment on potentially getting a -- what's the word for it, any kind of relief on that? And then also, where do you stand on CO2 purchases? What's the operator telling you there? And what is the cost structure and production profile look on Delhi in 2027?

Okay. Let's see. There's a lot of parts to that. So on the contract, right, so what we're past is the catch-up for the previous period, right? So going forward, it's not going to have anything like that because that included darn near a year of catch-up, right? So -- and look, we expect that between us and the operator there, we'll strive to get the best contract we can to sell our product for as much as we can. And I think recently, it trades a lot of times more in line, Ryan, correct if I'm wrong, with Louisiana Light Sweet. And that has been now a premium. And so the contracts, it's -- what it's selling for is looking pretty good at the moment.

We actually got a premium to WTI in the fourth quarter at Delhi. Some of that was the LLS differential like Kelly said, some of it is the way that just the -- they call it a WTI roll, which is trying to get trade month synced up with calendar month. And when you have prices increase like that, you can get benefits. So overall, though, yes, I mean, we feel comfortable about the differentials from Delhi in general as it relates to our broader portfolio.

And then on the CO2 side of the world.

Well, we're not going to -- they're not purchasing any more CO2, and there are no plans right now to do that. We think there's plenty of CO2 generated from the gas stream that comes out of the ground that we put back in. So it's more of maintaining reservoir pressure there, which Exxon says they're doing. And then what was the other part of the question that you asked, Poe? -- because there was about 4 questions.

No, I think I was trying to ask if there's any rebate or any way to potentially mitigate that catch-up. I think you had talked about on the last call, potentially trying to get some kind of...

Yes. So I think -- so what you're referring to is we would have the opportunity to take our production in kind and find a competing contract. And at certain times, it makes sense. I mean, just however, the way things are going right now, I think the contract we have there is, at the moment anyway, pretty competitive. So.

Sounds good. And then just if I could squeeze one last one in. You sold assets in April, $3.5 million generated a little more of $3 million. Any potential asset sales going forward looking into the rest of 2027?

Yes. So just let's put a fine point on that. Those were nonproducing assets that we essentially had valued at not being put on for several years to come. And so they have value to the right sort of person with a longer-term hold and no need to have them necessarily convert super quickly. So if that situation, if we find an area like that where we can high-grade the portfolio and move some of that capital into more near-term expected production, that's something we will always consider. So I hope that answers your question.

Yes. It sounds like sort of the herd is culled and you're going forward with what you have now.

Yes. And what -- I mean, it really does make that acquisition of the SCOOP/STACK minerals on the stuff that we really value near term an even better acquisition.

The next question will come from Sergey Pigarev with Freedom Finance.

What we've seen recently on natural gas prices is actually higher differentials to Henry Hub and quite low Henry Hub prices. So when do you think -- and maybe you already say it, differentials can normalize? And when do you think this additional demand from data centers, LNG can drive benchmark higher?

Yes. So Sergey, this is Ryan. On the differentials, a lot of what you saw weakness, especially in the fourth quarter was on the West Coast. We kind of talked about it being a really, really warm winter and storage being unusually high on the West Coast. We have seen it actually be more of a warm summer now and some of that storage has been worked off. So differentials have gotten much, much better on the West Coast, maybe not quite back to historical standards, but they're looking a lot better than they were in the last quarter. So we've already seen the improvement there. I would say in the Barnett and other areas, differentials have kind of been within historical norms. On the Henry Hub side, we are fairly well hedged at prices that are above the strip right now. So we are protected on Henry Hub there. And Kelly can give you his two cents, too, on just the pricing in general, but I do think that you have seen some weakness in Henry Hub due to additional production, some of the Permian production coming through to the Gulf Coast with the new pipeline. So obviously, that's weighed a little bit on the Henry Hub pricing. But -- and also the other big one being that it's actually the -- we think that the price is kind of anticipating a warm winter right now. You've got people worried about the Super El Nino going on. And so a lot of the pricing is already assuming that the winter is very warm.

Yes, Sergey, I agree with Ryan on that wholeheartedly. But I tell you what, we are excited about the prospects of the non-weather-related incremental demand that we see coming on over the near and medium term as significant drivers that are, like I said, completely outside of weather, weather is always going to matter. And I think Ryan is right, the current sort of strip is anticipating a warm winter. If that doesn't turn out, I think you'll see a big move. If it does, I think it's kind of already priced in. And then again, as we go forward over the next 2, 3, 4, 5 years, and you see LNG growing very significantly, you see more power growth, right? Just the call on power itself is often estimated to be pretty staggering. And if you just hold natural gas's sort of current percentage of that incremental power growth, there's a whole bunch of new demand for natural gas that will just be its piece of the power growth. And that -- again, that's excluding any increase in natural gas portion of that. So I do think -- and again, you're seeing more exports to Mexico. Lots of things pulling on U.S. sort of demand and potentially bringing it elsewhere and should put a strengthening under the market over the time. But in the meantime, if you have a super warm winter, it's going to put a sort of cap on current pricing.

The next question is a follow-up from Jeff Robertson of Water Tower Research.

Ryan, just a follow-up to the question regarding the RBL. Did the $73 million temporary increase or the $8 million actually temporary increase, did that include the reserves in the Midland acquisition and based on year-end 2026 reserve report?

Yes, effectively, I mean, that's what the additional capacity was for is the engineered reserve report on the Midland side. Now obviously, when we do our full redetermination in a couple of weeks here, it will use our year-end reserve report for all of our assets, right, to kind of look at that again. But that's the way to think about it is the incremental $8 million was effectively driven by the Midland minerals.

Again, really probably only relates to the PDP side of that, I would say.

That's right.

This concludes our question-and-answer session. I would like to turn the conference back over to Mr. Kelly Loyd for any closing remarks.

As always, we want to thank you all for taking your time to join us here, and we welcome you to follow up if you need any clarification on anything we said. Thank you very much.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.