MGY - NYSE

Good morning, everyone, and thank you for participating in Magnolia Oil & Gas Corporation's Fourth Quarter 2025 Earnings Conference Call. My name is Chloe and I will be your moderator for today's call. [Operator Instructions] Our call is being recorded. I will now turn the call over to Magnolia's management for their prepared remarks, which will be followed by a brief question-and-answer session.

Thank you, Chloe, and good morning, everyone. Welcome to Magnolia Oil & Gas' Fourth Quarter Earnings Conference Call. Participating on the call today are Chris Stavros, Magnolia's Chairman, President and Chief Executive Officer; and Brian Corales, Senior Vice President and Chief Financial Officer. As a reminder, today's conference call contains 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. Additional information on risk factors that could cause results to differ is available in the company's annual report on Form 10-K filed with the SEC. A full safe harbor can be found on Slide 2 of the conference call slide presentation with the supplemental data on our website. You can download Magnolia's fourth quarter 2025 earnings press release as well as the conference call slides from the Investors section of the company's website at www.magnoliaoilgas.com. I will now turn the call over to Mr. Chris Stavros.

Thank you, Tom, and good morning, everyone. We appreciate you joining us today for a discussion of our fourth quarter and full year 2025 financial and operating results. I plan to briefly speak to last year's results, which closed out another year of strong, consistent performance and execution showing the beneficial characteristics and merits of our differentiated business model and during a year of elevated product price volatility. Our model has allowed us to deliver strong free cash flow and cash returns to our shareholders resulting from superior asset performance and our continued focus on capital discipline, cost containment and visible efficiency improvements. I'll conclude by providing an outlook of Magnolia's 2026 capital and operating plan which is expected to deliver moderate growth with a similar level of capital spending that provides us with further opportunities to capture low-cost resource across our acreage position. Brian will then review our financial results in greater detail and provide some additional guidance before we take your questions. Beginning on Slide 3 of our quarterly investor presentation and looking at the highlights, Magnolia delivered another solid quarter and year of performance marked by steady execution of our capital-efficient business model and our high-quality assets. I'm particularly proud of our ongoing dedication and focus shown by both our operating teams in the field and our Houston staff. Their continued hard work and diligence is a significant factor behind Magnolia's success. Our business performed exceptionally well throughout the year, driven by stronger-than-expected well results, improved efficiencies, lower unit costs and our committed -- commitment to capital discipline, as I mentioned. For the full year 2025, total company production grew by 11% to approximately 100,000 barrels of oil equivalent per day with oil production growing by 4% and averaging nearly 40,000 barrels per day. Operationally, we continue to make strides in reducing our field level cash operating expenses, which declined by 7% to $5.12 per BOE during 2025. The better-than-expected well productivity we experienced during the first half of last year not only provided us with higher production growth in 2025, but also allowed us to save capital by deferring some well completions into this year. Our teams were also able to drive a more efficient drilling and completions program last year in Giddings with our average drilled feet per day increasing by 8% and with completed feet per day improving by 6%. Turning specifically to the fourth quarter, we achieved a new company record for our production, averaging nearly 104,000 barrels of oil equivalent per day and 40,700 barrels of oil per day. These both marked a sequential increase of 3% and reflected the continued strong performance from our wells. Financially, the quarter and year were equally strong and aligned with our goal of generating consistent and sustainable free cash flow through disciplined capital allocation. Our fourth quarter adjusted net income was approximately $71 million or $0.38 per diluted share with adjusted EBITDAX coming in at $216 million. Our drilling and completion capital for the period was roughly $117 million, representing 54% of our adjusted EBITDAX. Pretax operating margins averaged 33% for the year despite a more than 15% annual decline in our oil price realizations. Our low reinvestment rate enabled us to generate free cash flow of more than $425 million for the full year. We stood by our commitment to return a significant portion of that free cash flow to our shareholders, distributing approximately 75% through a combination of our base dividend and share repurchases. In total, we repurchased approximately 8.9 million shares throughout the course of 2025, reducing our diluted share count by roughly 4.5%. This not only accretes value on a per share basis, but also reinforces our business model that leads to a serial compounding of value. Our balance sheet ended the year in a position of strength, allowing us to navigate product price uncertainty and provides us with ample liquidity and a cash balance giving us flexibility to selectively pursue opportunistic bolt-on additions to our portfolio. As shown on Slide 4, our strategy is designed to produce steady mid-single-digit total production growth, high pretax margins and reliable free cash flow while maintaining a low reinvestment rate and a strong balance sheet. The strength of this model and the strategy is clear when looking at Magnolia's longer-term performance across these key financial metrics. Looking at Slide 5. Magnolia has maintained one of the lowest capital reinvestment rates among the U.S. oil and gas producers over the past 5 years, while delivering one of the highest rates of production growth per share. As shown on Slide 6, Magnolia continues to achieve strong pretax operating margins, driven primarily by our low-cost, high-quality asset base, which is also in close proximity to large consuming markets on the U.S. Gulf Coast. Slide 7 highlights the continued strength of our balance sheet, which remains best-in-class in the industry. Maintaining low leverage is a critical part of our strategy as it reduces financial risk while preserving substantial flexibility and strategic optionality. While many oil and gas operators often excel in 1 or 2 of these areas, we believe that our combination of our low capital reinvestment rate, above-average per share growth, high operating margins and minimal debt is unique, especially for a small to midsized operator. This powerful recipe allows us to generate high corporate returns, maximize our free cash flow generation and sustain our strong and consistent capital return program for shareholders. Slide 8 illustrates our corporate level returns showing 2025 as another strong year with return on capital employed ROCE of 18% and well above our cost of capital despite year-over-year lower oil prices. Over the last 5 years, Magnolia has generated an average ROCE of 34% and more than 3x our weighted average cost of capital. These exceptional returns stem from our prudent capital allocation, consistent low debt levels, ongoing share repurchase program and perhaps most importantly, our low-cost, high-quality assets. Case in point, Magnolia added approximately 50 million BOE of proved developed reserves during the year. When accounting for all expenditures to add these reserves, this resulted in organic proved developed finding and development costs or F&D of $9.25 per BOE. During the 3-year period from 2023 to 2025, Magnolia's organic proved developed F&D cost averaged $9.85 per BOE. This demonstrates our high quality and low cost of supply asset base. Looking ahead into 2026, we're committed to the principles that have guided us from the start and have proven to be successful thus far. We plan to remain fiscally prudent and disciplined with our capital spending expected to be approximately flat year-over-year while delivering total production growth of approximately 5%. As I've often said, Magnolia's primary goals and objectives are to be the most prudent and efficient to be the most efficient of our -- and our best-in-class oil and gas assets to generate the highest return on those assets, while spending the least amount of capital on drilling and completing wells no matter what the product price. Last year was another example of our successful delivery on these goals. We achieved double-digit production growth with less capital than originally planned, repurchased more than 4% of our outstanding shares recently announced a 10% increase in our dividend, our fifth consecutive annual increase and completed approximately $67 million of bolt-on acquisitions, furthering our resource opportunity set. To summarize, Magnolia is well positioned and consistently guided by the principles of our business model. Our high-quality assets and strategy of continued capital spending discipline, proactive cost management and pursuit of further operational efficiencies should serve us well during periods of product price volatility. Our consistent policy of low leverage and the lack of commodity hedges is central to our strategy, providing us with downside protection while also allowing for upside to product prices and the ability to generate value through commodity cycles. I'll now turn the call over to Brian for a review of our financials and provide some additional guidance.

Thanks, Chris, and good morning, everyone. I will review some items from our fourth quarter and full year results and refer to the presentation slides found on our website. I'll also provide some additional guidance for the quarter -- for the first quarter of 2026 and the remainder of the year before turning it over for questions. Magnolia ended 2025 with a strong performance across our operations. Starting on Slide 10. During the fourth quarter, we generated total adjusted net income of $71 million or $0.38 per diluted share. Our adjusted EBITDAX for the quarter was $216 million with total capital associated with drilling completions and associated facilities of $117 million, representing 54% of our adjusted EBITDAX. For the full year, adjusted EBITDAX was $906 million with D&C capital representing 51% of EBITDAX. Fourth quarter production volumes grew 11% year-over-year to 103,800 barrels of oil equivalent per day. For the full year, production volumes grew 11% to 99,800 barrels of oil equivalent per day with oil growth of 4%. During the year, we repurchased a total of 8.9 million shares and our diluted share count fell by 4% year-over-year. Looking at the quarterly cash flow waterfall chart on Slide 11. We started the year with $260 million of cash. Cash flow from operations before changes in working capital was $906 million with working capital changes and other small items impacting cash by $41 million. Throughout the year, we added $67 million of bolt-on acquisitions. We paid dividends of $117 million and allocated $205 million towards share repurchases. We incurred $469 million on drilling completions and associated facilities and leasehold and ended the year with $267 million of cash. Looking at Slide 12. This chart illustrates the progress in reducing our total outstanding shares since we began our repurchase program in the second half of 2019. Since that time, we have repurchased 81.8 million shares leading to a change in weighted average diluted shares outstanding of approximately 27% net of issuances. Magnolia's weighted average diluted share count declined by more than 2 million shares sequentially, averaging 188 million shares during the fourth quarter. As Chris discussed, the Board recently approved a 10 million share increase to our share repurchase authorization leaving 12.9 million shares remaining under our current repurchase authorization, which are specifically directed towards repurchasing Class A shares in the open market. Turning to Slide 13. Our dividend has grown substantially over the past few years, including a 10% increase we recently announced to $0.165 per share on a quarterly basis. Our next quarterly dividend is payable on March 2 and provides an annualized dividend payout rate of $0.66 per share. Our plan for annualized dividend growth is an important part of Magnolia's investment proposition and supported by our overall strategy of achieving moderate annual production growth, reducing our outstanding shares and increasing the dividend payout capacity of the company. Magnolia continues to have a very strong balance sheet, and we ended the quarter with $267 million of cash. Our $400 million of senior note does not mature until 2032. Including our fourth quarter ending cash balance of $267 million and our undrawn $450 million revolving credit facility, our total liquidity is approximately $717 million. Our condensed balance sheet as of December 31 is shown on Slide 14. Turning to Slide 15 and looking at our per unit cash costs and operating income margins. Total revenue per BOE declined 13% quarter-over-quarter due to the decline in oil prices. Our total adjusted cash operating costs, including G&A, were $10.64 per BOE in the fourth quarter of 2025. Our operating income margin for the fourth quarter was $9.85 per BOE or 30% of our total revenue. The decrease in our quarter-over-quarter pretax operating margin was entirely driven by the decrease in commodity prices and were further benefited from lower DD&A expense. On Slide 16, Magnolia continues to have a very successful organic drilling program. The total proved developed reserves at year-end 2025 were 167 million barrels of oil equivalent. Excluding acquisitions and price-related revisions, the company added 50 million barrels of oil equivalent of proved developed reserves during the year. Total drilling and completions capital was $461 million in 2025, resulting in organic proved developed F&D cost of $9.25 per BOE and reflective of our current drilling program. The 3-year average organic proved developed F&D cost was $9.85 per BOE. Turning to guidance. We expect our 2026 drilling completions and facility capital to be in the range of $440 million to $480 million, which includes an estimate of nonoperated capital that is similar to that of 2025. At the midpoint, this is similar to prior year's capital cost despite planning more wells in 2026. We expect first quarter D&C capital expenditures to be approximately $125 million and anticipate this to be the highest quarterly rate of spending for the year. Total production for the first quarter is estimated to be approximately 102,000 barrels of oil equivalent per day, which includes approximately 1,500 barrels of oil equivalent per day of winter weather impacts experienced in January. Total full year 2026 production growth is expected to be approximately 5%. Oil price differentials are anticipated to be approximately $3 per barrel discount to Magellan East Houston and Magnolia remains completely unhedged for all of its oil and natural gas production. The fully diluted share count for the first quarter of 2026 is expected to be approximately 187 million shares, which is 4% lower than first quarter 2025 levels. We expect our effective tax rate to be approximately 21%, with all of this being deferred. We are now ready to take your questions.

[Operator Instructions] The first question comes from Neal Dingmann with William Blair.

Nice to see another strong quarter, Chris and team. Chris, my first question is to jump right to the Giddings play. Specifically, looking at our well data, it suggests that a number of your recent wells not only continue to outperform the type curves, but they certainly appear to be some of the best drilled to date. I'm just wondering, with that said, has there been notable operational changes? Is it more because you're in pure development for a lot of that now? What do you attribute most of this continued upside to?

Neal, thanks for the question and also for pointing it out, we did notice it as well. They're producing -- the wells are very strong. They're producing a lot of everything. And I'm not sure exactly which specific wells that you're referring to, but many of them have performed very well. I can't point to anything specific or very different in terms of the completion design if that's a little bit of what you're asking. I think what you're seeing is simply the outcome of drilling into some very good rock. And I think when we take a lot of and make a lot of effort in terms of locating the wells and placing the wells. I think there's a better than decent chance that you'll see more of this. So I -- there's nothing specific that I can say that we've changed we've just gotten better at it with time.

No, that's obvious to see. And then second question, moving over to M&A. Simply, could you discuss -- I know you look at sort of all of the above, I think, as any -- or steward would. But what we've noticed out there, I mean we've seen record prices paid for Delaware. We've seen big prices paid for PDP heavy things. I guess, sort of twofold here, what are you looking sort of at all the above? And when it comes to the Giddings around your area in particular, are we seeing prices increase there like we've seen in a lot of these other areas?

Yes. Brian put some numbers around the bolt-on transactions, acquisitions, some of the ground game that has led to some of the bolt-ons that we've done over the last couple of years. And what I'd say is that it's not predictable. But we've done a good job, I think, with that ground game in Giddings, western Eagle Ford, Karnes area, I really do expect it to continue. Like I said, it's just tough to predict in terms of the timing. The competition, I would tell you it has risen over the last year, the larger the opportunity or maybe deal size or item that you might be looking for the tougher it is and maybe the more expensive it is. But we've done a good job of better understanding the things that we're looking for in terms of the subsurface and in and around where we currently operate. I'm not and never really have been a big proponent of very large PDP-heavy deals as you're more likely to pay full value for these or even higher. I think part of that is within your question in terms of what you might be seeing in the Permian and the Delaware. I really much prefer to focus on opportunities where we have more undeveloped upside but you're generally right, the prices for acreage has climbed. I mean, we're not out there looking to build a data center anytime soon. In terms of what you're seeing for what's happening in real estate or land prices. But for all I know, we could be competing with those -- with some of those who are looking to build a data center. I just don't know but it's certainly reflected in some of the elevated levels of pricing.

The next question comes from Phillip Jungwirth with BMO.

You called out the faster cycle times last year in the release. I was also hoping you could talk to well cost reductions and how those might have contributed to the better capital efficiency and lower F&D. And any expectations here as we go into 2026 or what you're seeing on the service cost front?

Yes, sure. We had been -- if I go back a year plus, we were looking at a standard cost of -- or the cost of the standard Giddings well as sort of maybe $1,100 a foot. And it was trending through that period up to now, maybe down towards $1,000 a foot. So I think that's sort of what we're looking at right now for a standard Giddings well, which is between 8,000 to 8,500 feet. So something between that probably gives you a reasonable estimate and maybe closer to $1,000 a foot, if that helps you. On the service cost, things are flat to slightly down into this year, but we'll see where this goes as far as commodity prices. We have regular conversations with our service partners, and we want to keep them working because they've been good partners. Most recently, this has been a tough way to make a living. I think the OFS market continue to experience some pricing pressure going through this year. And certainly, if prices for oil are $60 or below. We've locked in some of our service costs with our key providers through most of the first half of this year, and we'll be going back probably later in the spring to start looking at negotiating for things in the back half of the year and sort of close it out. But I feel as if we're in a good position and we're not looking to take advantage, but it's like I said, it's tough. And I get it but we're also in the business to make a margin as well. So things are favorable for us, less favorable for the OFS guys.

Right. Makes sense. And then we've seen really strong equity performance year-to-date for the sector and Magnolia. I mean, helped by geopolitical risk. So how tactical do you plan to be on the buyback? Do you view this as more programmatic as far as deploying it or maintaining dry powder to take advantage of any pull back given that we're likely to continue to see volatility?

Yes. The programmatic portion of it is the sort of 1% that we're minimally committed to as far as the way I think about it, I mean and there's -- it really does have teeth as it starts to chew into the shares outstanding and works with that sort of serial compounding that I mentioned, some of the tactical portion of it is what you saw probably for us in the fourth quarter where we underperformed, whether that was mean reversion or whatever, nothing really changed in the business, but we have the opportunity to sort of -- since we don't provide broker discretion, we sort of run it ourselves. We have the opportunity to sort of lean in or not. As things move along on the stock, it's going to be volatile. And if we see pockets of disconnect or I can't necessarily determine why that's occurring, we can lean in or not. And so should that occur again, we will.

The next question comes from Peyton Dorne with UBS.

Understanding the weather impacts for the first quarter I wonder if you could just touch on your expectations for the shape of the 2026 production outlook. Is it fair to think that beyond the step back here in 1Q that we should kind of see maybe a steady growth rate through the year? Or is there any other factors that we should keep in mind kind of as we go through 2026?

Yes, more or less. I mean, you can do the arithmetic. I mean, I think we've provided you with enough information where with the winter storm impact in the quarter and sort of adding it back, what it might have looked like perhaps without the occurrence of the event. So '26 is off to a good start, and I sort of see things gradually progressing through the year, but it's a little bit heavier capital outlay in the first half of the year, certainly the first quarter. So typically, that's sort of the way the curve works for us just in terms of timing of the spend, 4Q, 1Q is a little heavier, and then it sort of tapers off in the mid part of the year. And then again, rises on the capital as we ended out or finish out the full year. But the goal would be to spend as least as possible and generate better results on growth if we can. And I'm optimistic around the outcome of the wells. But generally, I think you'll see a gradual steady progress through the year on the volumes.

The next question comes from Tim Rezvan with KeyBanc Capital Markets.

I wanted to ask about the development approach for the year. You talked about 75% of activity on multi-well pads and Giddings almost identically to your comments a year ago. Can you sort of refresh our memories on sort of leading edge, the pad template. I know there's unique pads for different regions. But are you still sort of in that 3- to 4-well package size? Why not kind of push out laterals more to 10,000 feet or above? Just trying to kind of understand what development looks like as we think about incremental efficiency opportunities?

Yes. The 3 to 4 per pad is about -- is still about right. There's no real change there. We do have some 5-well pads. We do have some 2-well pads. But generally, I would tell you, it's probably around 3 to 4 on average. And the lateral lengths will vary. I mean we'll drill, if possible. I mean, we're not trying to drill shorter laterals. We'll drill longer laterals if and when we can. And that's part of the assist that we get with a little bit of the ground game, if we can acquire some adjacent or open acreage that could assist or help us out in that way. There's opportunities to do that. We drilled wells that are 12,000, 13,000 feet. And if we can do it, we will. But on average, it's sort of 8 to 8.5. That's sort of the typical program. that I would expect to see this year not very different.

Okay. That's helpful context. And if I could just circle back to the M&A question. You talked about some more competition on the larger side. I know there's at least 2 large packages right now in the market from public, not really in your Giddings backyard. But do you still feel the better opportunities on those sort of smaller side? Would there be interested in doing something big, potentially on that transformative side if the pricing was correct in your favor?

Yes. These are what I alluded to or mentioned before, probably -- not probably, they are more on the PDP heavy side, have been well developed, has sort of been through the machination of time and heavily drilled up. So you really -- you don't want to buy somebody else's decline curve. You never want to get involved with that if you can avoid it. So I'm looking for things that have untested upside or just upside undrilled acreage. And those are tougher things to be had. I'm just not looking to -- you're going to pay full value or better on this PDP heavy stuff. And so I think generally, that's what those larger things would look like. We probably also like to lean a little bit more on the liquids side on the oil side, if we can do it or find it. So I'm not averse to gas necessarily, but if we can -- if there's going to be some production that comes along with it, I'd probably prefer to have a little bit more on the oil side. The other thing, too, large deals come with obviously greater risk. And so you just want to be sure that you can manage this and if you have a good understanding of it. So whatever we're going to do or whatever going to look like, has to sort of start off with the understanding that we have a good firm view of what we're getting ourselves into subsurface-wise and whether or not we can continue to manage it going forward. So there's a lot of -- looking at old things that are being hived off by publics. It's interesting, but you just got to make sure you understand it well, and it's actually contributing to the business in a positive way fits into our model and can be accretive to the equity.

Okay. I appreciate the responses. And if I could just sneak a quick one in. Oil SKUs has been about 39% in the back half of 2025. As we look forward, should we still expect that 39% to 40% range to hold?

Yes. The percentage is a tough one, not tough from -- in terms of what it's going to be. It's just -- I'd rather speak in terms of absolute oil, and absolute oil I expect to grow 2% to 3% this year, and it will be a mix of Giddings and the Karnes area asset, so I'm confident around that. And if we can do a little bit better, we'll see. But the percentage considering the proportion of the program in Giddings, where you -- getting on average is running very much mid-30s, 35%, 36% thereabouts. And we're, call it, like you said, 40%, 39%, 40%. It's going to be in that range. And if you were able to add an asset or a little activity that could make you a little bit oilier, we'll just sort of see. But I'm very confident that on the low end, you're not going to sort of be 20% or something odd, you're going to be in that mid-30s or 40-ish or maybe even a touch better depending on things that are available to drill and that we fit into the program.

The next question comes from Leo P. Mariani with ROTH.

Just obviously, strong well performance in Q4, which you guys spoke of. Trying to get a sense of whether or not that's been primarily driven by the 240,000 acre development area? Or are you seeing some contributions from some other areas? You did reference some new development areas in your release. So I was just trying to get a sense of those new areas are on top of the 240,000 acres or kind of included in the 240?

I would tell you it's included in the 240 but that's not to say that we're not looking elsewhere and have plans to go outside the 240,000 with additional appraisal this year, which we will. So I'm looking forward to that. I'm looking forward to what the results may bring, and it's been very useful helpful to us up to now, and I expect it to be additive in terms of our resource going forward. So I'm optimistic around that. But to your question around where did it come from, it's sort of historical and it's really within the 240,000.

Okay. I appreciate that color. And then obviously, LOE was once again pretty strong this quarter in terms of being a low number. Just wanted to get a sense of kind of what's really been driving that? You guys have done a really good job at getting costs down. And I think from your prepared comments, I think you're still continuing to work on that. So how should we expect that to trend as we roll through '26 here?

So good question. The first quarter, obviously, we had the weather events with the freeze and there's just some extra things that need to be done to sort of compensate for that in terms of repairs and maintenance. I'm not going to dwell on it. It's not a huge deal, but you'll see a little bit of that, I believe, in the first quarter on LOE. And LOE seasonally is generally higher in the first quarter for field bonus payments, we have to pay our guys and hopefully, we pay them well. So there's some of that. So that's just seasonality. I will tell you, though, that they have done a very good job, an impressive job, frankly, in terms of bringing down costs in the field. I think we have additional things. They have some things up their sleeve that will work out in a positive way over time. And I'm confident that sort of the numbers that we're seeing in terms of continuing to trend down, I feel pretty good about it. So I think there's some additional room for improvement with some things we're working on.

The next question comes from Noah Hungness with Bank of America.

You guys gave a decently wide range for your '26 capital guide. Could you maybe put some color around what would push you either to the upper or lower end of that range?

There's not much that I can come up with that would push us to the upper -- in the current environment. So I'm confident that you're sort of in the middle part of that range or lower. We're not looking to do more and frankly, should we do better in terms of the well performance has occurred last year. We could find ourselves in a similar position where you just put off some of the spending or defer some completions or whatever, just because the performance is better. So if we can spend lower, less and have more free cash flow, that would be terrific. That is really the objective. So I'm simply giving a range really because just some of the product price volatility and uncertainty, should prices move higher and directionally higher and we see some reflation or pickup in service costs that could lead to it. But right where we are now, that's not something I'm anticipating.

That's really helpful. And for my second question is just on first quarter GP&T. During the winter freeze, we also saw really strong gas prices. Is that higher gas pricing going to potentially translate into higher GP&T for the quarter?

Maybe slightly. We expect GP&T to be relatively similar from what we've seen over the past couple of quarters. So I don't expect too much volatility there. Could it be slightly higher? Yes, but we're not talking quarters and it could be a couple of pennies or nickels.

The next question comes from Carlos Escalante with Wolfe.

I would like to pivot real quick to your D&C cost savings year-on-year. I learned yesterday from your own Tom Fitter that you've been running the same Patterson rig since Magnolia's inception, and I thought that's just the epitome of your industrial approach. So I wonder if you can, in a very succinct manner unpack how much of the D&C cost gains year-on-year have been on as a consequence of that industrial approach to the business versus any kind of service deflation? And perhaps with your additional commentary on how much more you can squeeze via that continued repetition on the drilling side specifically?

Well, it's a very good point in observation. I mean it's running these rigs, not just one, but both consistently over a multiyear period has led to a wonderful understanding of the field, the drilling challenges and capabilities that the assets bring to us. And so not just the rig, but the crews that we have and equipment really does provide us with that further understanding and capability and consistency that I think drive some of the efficiencies that we've been seeing. So if you want to call that the industrial approach, that's fine. But it does translate into benefits with time. The crews, the people, the equipment, all of it, we like what we have. We're always looking to continue to utilize those things. But at the same time, be competitive and look elsewhere, but there's advantages to having that consistency for sure.

That's very helpful. And as my second question and building on Noah's question. On capital, so if we exclude the 6 deferred sales that you had from '25 and then you include back the downtime from the production storm. In my mind, it stands the reason that your development capital, your maintenance capital is substantially down. I wonder if you can put maybe perhaps a number on where you see that, where you can hold your production flat? And I think that I'll add that as a backdrop, the industry hasn't been paid to grow for the past few years. So a lot of interesting things going on in the Permian Basin and the South in general with growing dynamics. So we could be trending the tide here. So wondering how you see that and if you can provide again that number on your maintenance capital as it stands today?

No. The capital is an interesting observation or point, setting aside the winter event. We're going to complete -- drill and complete a few more wells this year that is sort of embedded within the growth expectations that we have and some of that is largely fits into the program because of some of the efficiencies that we've generated over the years. But in terms of maintenance, probably -- I'm not sure -- we haven't tested it yet. So it's always hard to exactly come up with a very, very narrow range. But I would tell you, $400 million-ish feels about right, maybe a little less.

Carlos, maybe I'll just add, too. If you go look back in time, the last 5 years, we've spent about the same amount of money every year. Our production is up roughly 50%. We're drilling more wells each year generally, and that's driven by efficiencies. There's other things that can contribute to the decrease in total capital costs. But when you look at it as a whole, since the last 5 years has been relatively stable in terms of how much we spend on an absolute basis. And we're doing that with more production and more wells.

And factoring in the first part of your question around the industrial capabilities of the equipment and the drilling rig, I mean, all of that sort of comes together to allow that flatness, if you will, in terms of what you've seen or consistency on the capital over the last 5 years that Brian mentioned.

The next question comes from Phillips Johnston with Capital One Securities.

Just a few housekeeping questions on the modeling front. I know your average working interest on some of your acreage in Giddings has moved up with some of the recent bolt-ons. So what should we assume for your average working interest for this year's drilling program in both Giddings and Karnes? And just in terms of cycle times company-wide, are we still kind of running somewhere around 28 gross wells per rig -- per year per rig line?

I'll start with the second, '28. I mean that may be slightly aggressive, but it's not far off depending on where we are and exactly what we drill. And in terms of working interest in Giddings, I believe we've been able to move that up from the, call it, mid, maybe slightly higher 70% range. And I would assume something in the low 80s today.

Okay. Perfect. And you guys noted some deferred well completions from '25 into '26. I think the number was around 6. So just to clarify, would you expect your tail count this year to be about 6 wells higher than the number of wells that you drill? Or should we think about the company just operating with a higher working inventory of DUCs?

No, I wouldn't necessarily -- I mean, we don't purposefully look to add DUCs necessarily. But I think you're in the range, plus or minus ballpark of the half dozen that we sort of had coming in from last year.

The next question comes from Charles Meade with Johnson Rice.

Chris, I want to go back to the acquisition market. And I know you spoke a lot about this earlier in the Q&A, but I want to try to put the pieces together and see if I understand your thinking. When I think about the traditional oily parts of the Eagle Ford, that's going to all be PDP-heavy or almost anything would be PDP heavy. And then you think about something that has more undeveloped, which I think you said that's more interesting to you, those are mostly going to be down dip in gassier. And so am I -- and I think you said you weren't interested in gas. And so if I'm putting those pieces together, right, does that mean that you're not likely to be a really charge hard at those traditional Eagle Ford packages?

I wouldn't disagree with what you said as far as they're tough to find, but they're out there. So you just have to be -- remember, we're small. And so little things here and there can make a difference. And you just have to make the effort and poke around and we know a lot of folks. And so there are opportunities out there. You just have to set to try. The PDP heavy Eagle Ford and things like that, that you're referring to up dip, I'm not -- I'm less interested in those. It's difficult, it tends to be more scattered. There's less obvious synergies that are available because it's just sort of county to county, it's not homogenous. It's very different scattered like I said. So it's tougher to make it work as a public company. If you're private, you could do some of these things get away with it. It's not a big deal. But as a public company in terms of the way we think about things, it's a tougher way to make a living.

And then on -- I wonder if you could just give us a refresh on I think that there's a lot of bearishness in the ore market, but we recently saw $65. And so when you guys look at internal scenarios where you run $70 or $75 oil rig, what is the -- where does the extra cash go in your -- in the scenarios that you run?

On your oil comment, you're right. I mean the sentiment as we sort of got out of '25 was extremely negative. And maybe some of that is still lingering in there in terms of just available supply in the market is certainly ample oil. Personally, I've been more constructive. I think I've said this many times in investor meetings that we've had. Been more constructive on oil as you go into 2026, and then you have all these sort of geopolitical whack-a-mole events that sort of tend to pop up, and you don't know what's lurking around the corner. So those have sort of underpinned and helped, I guess, on oil just to remind everybody that 2/3 to 3/4 of the world's oil supplies and some pretty nasty places. And so it's -- that's not going to end anytime soon. The other thing, you've got other dynamics too. Global demand is pretty healthy. You've got sort of the economy that's pretty good. I'm sorry, but what your question is getting at, what exactly?

When you guys run scenarios at $70 or $75, where does the extra cash go? I mean does it go to more is the first thing, another dividend bump? Or is the first thing that ramp up share repurchases? Or is -- and part of that could even be, when does another rig come into the picture?

Another rig doesn't come into the picture. That's not the plan. So again, I say this again and again and maybe people don't believe me, but I mean the plan is to spend as little as we can or be the most efficient with the money in terms of drilling the fewest wells to continue to take advantage of the productivity gains that we see in the field and have some moderate growth. We're not chasing growth for growth's sake. So in a better-than-expected commodity product price scenario, we just sort of sit there, take the winnings. It's the advantage of having an unhedged outcome, if you will, structure and so we don't have any real financial risk in terms of the leverage. So we capture all the upside to commodity prices that will ultimately feed back to the shareholder and the way shape or form of like you said, and we could toggle this, whether it's dividends, share repurchase and/or just being opportunistic around redeploying some of the excess cash towards opportunistic acquisitions. So that's pretty much where the extra money would go.

The next question comes from Tim Moore with Clear Street.

And great execution and reliable capital allocation. And I'd just like Chris comments that another rig cost won't creep into the picture. But Chris, I just wanted to follow up on just another Giddings thread. How much more confident are you in future outcomes of new wells there, bringing more net acreage into the portfolio with some higher predictability than you were maybe 18 months ago? If you kind of could add any color on your look back of EUR predrill and post-drill results for new wells in Giddings. I mean they came out a couple of percent better. Or just any thoughts on that would be helpful.

I'm very confident because of the ongoing appraisal and even where you say maybe adding to that a touch of sprinkle of exploration, if you will, in and around some of our areas. So whether it's that or some of previous bolt-ons or things that we may be working on, there is a very good chance in there will be more opportunity set to work on that will deliver the types of results that we've been accustomed to seeing. So I'm very confident around that.

Great. And my only other question is mean without adding another rig, like you mentioned you own, how quickly can you really lean in and slightly ramp up drilling for a few extra wells in Giddings, if later this year, oil price is somewhere around 70%, I mean, I know you were able to quickly delay, I don't know, 6 completions last year. Could you flex that much on new wells? Or do you need a lot more lead time?

I mean, we could, but we won't. It's not -- it's just generally not the direction we would take it. Like I said, we set our plan at something that is -- we view as practical and prudent in terms of what we envision with the product price scenario that is conservative. And we'd like to grow within that outcome and the moderate growth that we talked about is what the assets are capable of delivering. We're not stretching for more than that. If the outcome turns out to be better than expected, that's great, but we won't chase more growth or necessarily just respond to the product price in that way. We'll just take the money and view it as winnings and we'll deploy it to -- or we'll provide it back to the shareholder and some fashion either share repurchases, most likely.

The next question comes from

Just one question for me. And you commented on this a little bit, but you have delivered some pretty significant gains in productivity this year that's allowed you to grow production more than originally planned at lower CapEx. Do you think that higher level of productivity is sustainable going forward? And maybe comment on how much of that productivity uplift is factored into your 2026 guidance.

There's -- we pretty much take a backward look on this and look at our drilling plan. The drilling plan, I would tell you and the anticipated outcome is not very different in terms of the sets of wells that we're expecting planning to drill as far as what this year's program. So there's a reasonable chance that things could turn out better than what we're predicting. Certainly, it turned out that way last year. But you can't -- there's no guarantee I mean so -- but there is a reasonable chance that some of that will occur in certain areas. So it's a balanced program. It's designed to sort of deliver moderate expectations for volume growth and factoring in some sorts of levels of risk. But I think as I look at the risk this year, frankly, it doesn't even feel as great as it was last year and last year turned out okay. So I think the outcome will be pretty good.

The next question comes from Paul Diamond with Citi.

Just a quick one for me. Just talked a bit about the improvement in drilling feet per day, completion feet per day and kind of just general overall cycle improvement. I guess just trying to understand, as we look forward, how much is up in that bone is there? Take the recent trend is indicative of what we should expect over the next 12 to 18 months or say it the thought there?

Yes. I can't speak to precise estimates or a factor of improvement that's coming in the next 12 to 18 months? Is it likely to improve? Yes. gradually, yes. And some of that is some of the -- what I mentioned in an earlier response, just the consistency and understanding of not just where we're drilling, how we're completing and the experience of not just the equipment but the personnel that are driving the effort. So as you understand more, you unlock more efficiencies with time, so I do expect that to gradually improve.