Magnolia Oil & Gas Corporation (NYSE:MGY) Q3 2025 Earnings Call Transcript

Magnolia Oil & Gas Corporation (NYSE:MGY) Q3 2025 Earnings Call Transcript October 30, 2025

Operator: Good morning, everyone, and thank you for participating in Magnolia Oil & Gas Corporation’s Third Quarter 2025 Earnings Conference Call. My name is Danielle, 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.

Tom Fitter: Thank you, Danielle, and good morning, everyone. Welcome to Magnolia Oil & Gas’ Third 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 third 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.

Christopher Stavros: Thank you, Tom, and good morning, everyone. Thanks, everyone, for joining us today for a discussion of our third quarter 2025 financial and operating results. I plan to highlight our quarterly results, which represent another strong period of consistent execution for Magnolia and continues to deliver on the capital-efficient program that we outlined during the first half of this year and one that’s provided us with more free cash flow. Brian will then review our third quarter financial results in greater detail and provide some additional guidance before we take your questions. We continually remind the financial community that Magnolia’s primary goals and objectives are to be the most efficient operator of our best-in-class oil and gas assets to generate the highest returns on those assets and while employing the least amount of capital for drilling and completing wells.

A substantial portion of the free cash flow Magnolia generates is returned to investors through our secure and growing cash dividend and ongoing share repurchases. And we continue to enhance and expand our asset base through bolt-on acquisitions stemming from our cumulative subsurface knowledge and experience near areas where we operate and understand well. Magnolia’s latest quarter is characterized by achieving these objectives, and our year-to-date performance demonstrates our ability to execute our business model despite the decline in product prices that we’ve seen recently. We operate a focused business with an emphasis on driving financial returns and do not plan to add incremental activity at current product prices. At Magnolia, our mission is straightforward, generating consistent and sustainable free cash flow through disciplined capital allocation, pursuing on [Technical Difficulty].

All that said, and turning to Slide 3 of our investor presentation, Magnolia delivered another strong quarter, and our overall business continues to operate exceptionally well. We achieved a record quarterly total production rate of 100,500 barrels of oil equivalent per day during the third quarter, representing year-over-year production growth of 11% with total production [Technical Difficulty] quarter saw low single-digit year-over-year growth despite a small sequential quarterly decline due to the timing of turn-in lines, while oil production at Giddings grew by nearly 5% compared to the prior year. As we are now well into the fourth quarter, our production is off to a very strong start, and we anticipate both record total production and oil production in the current period.

Continued strong well performance during the year is expected to provide us with full year 2025 total production growth of approximately 10% and well above our initial guidance of 5% to 7% at the start of the year. Our Giddings well results have not only outperformed our expectations, but have exceeded levels of the last couple of years and despite a similar drilling and activity program. The outperformance led us to defer the completion of several wells into next year, allowing for a reduction in our capital earlier this year and is expected to result in a roughly 5% savings in spending during 2025. This had the dual benefit of improving our free cash flow during 2025 as well as enhancing our operational flexibility as we move and look into 2026.

Our adjusted EBITDAX for the third quarter was $219 million and operating income margins were 31% during the period, while our annualized return on capital employed was 17%. Each of these metrics was supported by solid overall production volumes during the quarter in addition to strong relative price realizations for both natural gas and NGL production. Our disciplined approach around spending, a focus on financial returns, including our efforts and initiatives to improve the efficiency of our D&C program, all contributed to limiting our capital reinvestment rate to 54% of our adjusted EBITDAX during the third quarter. Our low reinvestment rate helped generate a strong level of free cash flow in the quarter of $134 million. We returned 60% of this free cash or approximately $80 million to our shareholders through the repurchase of more than 2.1 million Magnolia shares and the cash payment of our quarterly base dividend.

Both our consistent share repurchase program and the secure growing base dividend are a mainstay of Magnolia’s ongoing investment proposition. Incorporating these outlays, we ended the quarter with $28 million of additional cash and with a cash balance of $280 million at quarter end, which was the highest level of the year. As I mentioned, we expect to end the year on a strong note and with record oil and gas production in the fourth quarter and with capital spending of approximately $110 million. As we did during 2024, we continue to focus on our field level operating costs, which have reduced our lease operating expenses through capturing additional production efficiencies in such areas as water handling and fluid management as examples. These and other initiatives are the result of continuous improvements in how we plan, drill, complete and operate our wells.

Additional drilling and completion efficiencies that we expect to realize will accrue to the business through additional learnings and the further delineation of our Giddings asset. We expect these efficiencies to accumulate at a measured pace and have no plan to accelerate our activity to pursue this. Looking ahead to 2026, we remain committed to our business model, which limits our capital spending to 55% of our adjusted EBITDAX or gross cash flow. Similar to 2025, we plan to operate 2 drilling rigs and 1 completion crew next year and expect to allocate a modest amount of capital toward appraisal activities in both Giddings and the Karnes area and to further enhance our resource opportunity set. Assuming current product prices, we expect that our 2026 program would deliver mid-single-digit total production growth with capital spending at similar levels to 2025.

This also allows for significant free cash flow generation in support of our investment proposition, providing a secure and growing dividend and consistent share repurchases. We remain well positioned with ample financial and operational flexibility, allowing us to adapt within a volatile product price environment. When we ask our larger shareholders why they’re invested in Magnolia, a common reply is because you do what you say you’re going to do. Since our founding more than 7 years ago, Magnolia has consistently executed around the principles of its differentiated business model, which includes our strong balance sheet and disciplined capital spending philosophy designed to maximize free cash flow generation from our high-quality assets.

We remain committed to our business model and our strategy that has helped compound per share value for Magnolia shareholders. I’ll now turn the call over to Brian to provide some further details on our third quarter 2025 results and some additional guidance for the fourth quarter.

Brian Corales: Thanks, Chris, and good morning, everyone. I’ll review some items from our third quarter results and refer to the presentation slides found on the website. I’ll also provide some additional guidance for the fourth quarter of 2025 before turning it over for questions. Beginning on Slide 5, Magnolia delivered a strong quarter as we continue to execute our differentiated business model. During the third quarter, we generated adjusted net income of $78 million or $0.41 per diluted share. Our adjusted EBITDAX for the quarter was $219 million with total capital associated with drilling, completions and associated facilities of $118 million, representing 54% of our adjusted EBITDAX. Third quarter production volumes grew 11% year-over-year to 100,500 barrels of oil equivalent per day while generating free cash flow of $134 million.

Looking at the quarterly cash flow waterfall chart on Slide 6. We started the quarter with $252 million of cash. Cash flow from operations before changes in working capital was $247 million, with working capital changes and other small items impacting cash by $5 million. We added $25 million of small bolt-on acquisitions comprised of additional acreage, working interest and royalties that we discussed last quarter. During the quarter, we paid dividends of $29 million and allocated $51 million toward share repurchases. We incurred $119 million of drilling completions, associated facilities and leasehold and ended the quarter with $280 million of cash. Our cash position is the highest it has been all year despite lower oil prices and acquiring approximately $65 million of bolt-on acquisitions during the year.

Looking at Slide 7. 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 79.4 million shares, leading to a change in weighted-average diluted shares outstanding of 26% net of issuances. Magnolia’s weighted average diluted share count declined by approximately 2 million shares sequentially, averaging 190.3 million shares during the third quarter. We currently have 5.2 million shares remaining under our repurchase authorization, which are specifically directed towards repurchasing Class A shares in the open market. Turning to Slide 8. Our dividend has grown substantially over the past few years, including a 15% increase announced earlier this year to $0.15 per share on a quarterly basis.

Our next quarterly dividend is payable on December 1 and provides an annualized dividend payout rate of $0.60 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 $280 million of cash. Our $400 million of senior notes does not mature until 2032. Including our third quarter cash balance of $280 million and our undrawn $450 million revolving credit facility, our total liquidity is approximately $730 million. Our condensed balance sheet as of September 30 is shown on Slide 9.

Looking at Slide 10 and looking at our per unit cash costs and operating income margins. Total revenue per BOE declined approximately 12% year-over-year due to the decline in oil prices, partially offset by an increase in natural gas prices. Our total adjusted cash operating costs, including G&A, were $11.36 per BOE in the third quarter of 2025, and our operating income margin for the third quarter was $10.98 per BOE or 31% of our total revenue. Turning to guidance. Fourth quarter D&C capital expenditures are expected to be approximately $110 million, which would bring the total capital for the year to about the midpoint of our previously reduced annual capital budget. This includes an estimate of non-operating capital that is similar to that of 2024.

We are reiterating our full year 2025 outlook for total production growth of approximately 10% compared to our guidance at the beginning of the year of 5% to 7%. Total production for the fourth quarter is estimated to be approximately 101,000 barrels equivalent a day, and we expect that total production and oil production for the quarter to be at the highest levels of the year and new Magnolia records. Our price differentials are anticipated to be approximately a $3 per barrel discount to Magellan East Houston, and Magnolia remains completely unhedged on all of its oil and natural gas production. The fully diluted share count for the fourth quarter of 2025 is expected to be approximately 189 million shares, which is about 4% lower than fourth quarter 2024 levels.

We expect our effective tax rate to be approximately 21%. And with the passing of new legislation during the third quarter, we expect 0 cash taxes for full year 2025. We are now ready to take your questions.

Q&A Session

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

Neal Dingmann: Nice quarter and nice to be back on. Chris, my question for you or Brian, you continue to have these pretty amazing operational efficiencies. And I’m just wondering if that continues at the pace that we’ve seen driven by these Giddings wells, could you envision — I mean, again, I think about, will you keep — would you accelerate production potentially even more than 10%? Would you be able to or would you think more so about you’d even be able to cut CapEx? I’m just wondering when you toggle those 2 and if you keep having the same upside, where could we see those benefits lie next year?

Christopher Stavros: Neil, thanks for the question. Good to have you back. Look, we can do largely anything we’d like to do, or we want to do within the context or framework that you mentioned. I think the point is, we want to stay true to the business model, and it is — it works for us and it works for our shareholders in terms of maximizing the free cash flow that we have to give back to them. So rather than elevating activity levels, if you will, or rushing to get there, they will get there with time and over time. And as we continue to pursue new areas and probe around the vast acreage position that we have in Giddings and also parts of Karnes and appraise more of it and bring more of it into the fold, we will have more of the way in realized efficiencies.

I’m very confident of that. We’ve seen it. There’s a litany of things that I can tell you that the teams are working on that they currently see rather than — I could spend 20 minutes on talking just about that, and we’re going to talk more about it as a team. So that will happen as we go forward. There’s no real reason to rush the activity levels or rush the production volumes or reach or stretch for higher levels that could get you into a situation where you’re forced to spend that much more as your volumes sort of decline and get you on that sort of treadmill. So, we sort of live within the model, moderate mid-single-digit growth. If the assets exceed that, which oftentimes they have over the life of Magnolia, we’ve seen that better-than-expected performance, we’ll take it.

But we’re not going to overstretch or overreach on the capital or activity just because we’ll live within the model and we’ll live within our governor of the capital. And I think in that way, everyone will be satisfied.

Neal Dingmann: No, I’d love that if you’re able to do that. And then just lastly, when you look at M&A, you guys have been doing a fantastic job of replacing your — more than replacing your inventory. When you look at just sort of white space in your general area, is there still plenty of white space? Or how would you describe the — I don’t know, I guess, the ability just to continue to do these strategic bolt-ons. You guys have done a nice job, as I said, replacing the inventory as there’s still a lot of potential to do so.

Christopher Stavros: Yes. No, good question. There’s a fair amount of white space, as you called it, and there’s a fair amount of smaller private operators that — things that we’ll always evaluate. It has to be the right fit. And I will say that, first and foremost. It has to be the right fit for Magnolia. It has to, at its essence, actually improve the business, improve the company, improve our durability to fit into the model and extend what we have been able to do over the last however many years. So, if we can find something that fits that way or looks like us, we will do that or we will certainly consider it if it presents the proper fit. There may be some things like that. Not a day goes by where I don’t get an e-mail or a phone call from a banker, they’re transactional, so they love to reach out.

But they may not like us very much because the answer is more likely no than yes. So, we haven’t found any of those things. But we continue to try and chip away and these are just, over time, additive to our business. A lot of it or certainly some of it has come through the appraisal program that we’ve had over the years where we learn about a certain area, we like it, we tend to figure it out, and then we look for more of it in the way of filling in that white space if it can be had. So, we’ll continue to do some of those things.

Operator: The next question comes from Tim Rezvan from KeyBanc Capital Markets.

Timothy Rezvan: I want to start, Chris, you mentioned in your prepared comments and in that last response, appraisal work going on at Karnes. There’s a market perception that Karnes is sort of on its last legs as one of the earlier shale plays. So, can you talk about what you’re referring to with the appraisal activity there? Is that non-op? Is it operated? Is it Austin Chalk or something else? Just curious any color you can provide.

Christopher Stavros: Well, I wouldn’t write Karnes off just yet. Certainly, good rock is good and tends to have a long life. So that is good rock and some of the best, they’re in Karnes. We’re continuing to look at that and see what else we can do, what iteration of it that we’re on. And fortunately, I still think it’s relatively early for us. So, there may be more to be had there, and we’ll continue to probe around. I’m not going to say exactly what we’re going to do, but — or exactly what we’re planning on doing, but there will be some things that we will test that may have some upside or provide some extended life, if you will, to Karnes. That would not surprise me in the least. The question is always, when you do these appraisal things, what do the economics look like?

There’s no unlikelihood that we’re not going to find producing quantities of oil and gas. That’s certain, for sure. The question is, can we do it economically and provide a good amount of duration around it. I think there’s a reasonable chance around that. So, I’m not — certainly not going to write it off. And again, I would say the same thing with Giddings, although Giddings is a lot bigger just in terms of its footprint, and we’re quite active there, too, and we have some things planned as well. So, I think I’m optimistic.

Timothy Rezvan: Okay. I guess, we’ll have to stay tuned into next year. And then my follow-up is sort of a similar theme. The Western Haynesville evolution has been interesting and now there’s folks leasing sort of up to your acreage line. I’d be shocked, I think, if you did some appraisal drilling there. But is there a discussion at the Board level about trying to understand if you think you have that resource? And do you have the deep rights?

Christopher Stavros: That’s a bit further afield in the area that you’re referring to compared to where we are. We currently don’t have an area up and around where you’re talking about. There are other areas within Giddings that have extensive amounts of natural gas exposure. We’ve talked about that at the organizational level throughout. And again, as I mentioned earlier, it’s more about, to some extent, economics as opposed to quantities of producible hydrocarbons. We know it’s there. It’s just, can we figure out a way to make it more economic.

Operator: The next question comes from Carlos Escalante from Wolfe Research.

Carlos Andres E. Escalante: I’d like to go back real quick to your discussion on appraisal — on your appraisal program. So if — just taking an early look at how you intend to manage your appraisal program in 2026, particularly in the event of any weakness, I wonder how you would intend to manage that and what are the levers that you could pull? Because at your current adjusted EBITDAX and CapEx, we certainly think that implies, at least in our view, that you won’t touch your growth capital until perhaps anywhere close to $50 per barrel WTI. So, I wonder if you can frame the appraisal program in the context of those levers and again, in the event of a sustained oil weakness.

Christopher Stavros: Yes. Thanks for the question, Carlos. Look, the appraisal program has been quite beneficial to Magnolia in terms of our resource and capabilities over time and expanding the footprint in Giddings. So, I’d be somewhat reluctant to take a machete to that program and just cut it off too harshly. You need to do what you need to do and some mix of oil and gas prices. But in the current outlook or in the current sort of price dynamics that we’re seeing, there is still room for a reasonable amount of that type of activity, and we’ll continue with that. Look, I say this internally all the time, few ways to find resource and you decline every day, just like all our peers, you either buy it or you find it. And we continue to look for ways to supplement our existing resource and the appraisal program for us up to now has worked out exceptionally well.

And — particularly in Giddings, we’ve tested some new concepts. We’ve tested some of the boundaries. There’s almost always really — not almost, but really always going to be producible amounts, again, of oil and gas when we drill. The question is, can we make the economics of a particular area work well for us that fit into our matrix of returns and a competitive for other — competitive for capital. So, we’ll continue to do that. It’s an important element of what we do, and we’ll continue to examine different parts of it and try to high-grade the program, if you will.

Carlos Andres E. Escalante: Wonderful. Appreciate that, Chris. And then on my follow-up, I think that certainly to us, at least from a [ vantage ] point, one of the many sell points that Magnolia has as an organization is its ability to capitalize on natural gas realizations compared to a lot of your oil levered peers. We just had a very interesting quarter in Waha, for example. So, just wondering where you are today and considering all the reshuffling that you see just in the backyard of where you are with Gulf Coast LNG growing and growing, if there are any kind of initiatives that you have for sustaining your organizational level that may be aimed to further improve that and further gain that edge that you have over some of your oil level peers?

Christopher Stavros: Well, thanks for the commercial message. I really appreciate it on the natural gas realizations. I would agree with you that we’ve been able to benefit from some strong realizations on a year-over-year basis and into most of ’25. The answer is, I don’t exactly know. I mean there’s a lot of complicated factors. Had we taken actions based on some impressions or opinions that we had heard, say, a year ago and done some things to perhaps consider hedging basis or even consider options such as that, we probably would have been wrong. The impact of what you’ve seen up to now coming out of the Permian with it, and in some of the associated gas producing areas as we move more gas to Waha, et cetera, hasn’t seemed to influence it yet.

I don’t know if it will, but I would have — others said that it would have and they were wrong, and there’s a lot of other variables and factors that may offset that. So, I’m not necessarily willing to lean in and make something fully deterministic on somebody’s view because there’s just so many moving parts.

Operator: The next question comes from Charles Meade from Johnson Rice.

Charles Meade: Chris, I’d like to go back to the A&D market and ask a question there. Can you offer your view? Have you seen anything different on the packages that you look at around Giddings, either in the quality of what is available, what’s being brought forward or the ask that you’re seeing relative to the value?

Christopher Stavros: Are you referring to South Texas or Giddings specifically or just South Texas inclusive of the entire trend?

Charles Meade: I was asking more specifically about Giddings, but I’d be curious to hear whatever view you want to share on the whole kind of Eagle Ford Austin Chalk trend, if you care to.

Christopher Stavros: Yes. Well, let’s start with Giddings. Giddings is, it’s fairly — in terms of the bigger packages or bigger concentrated assets, it’s fairly concentrated. There’s us and a large private player without naming names. And then there’s probably a smattering scattered positions of a variety of private players. There are very few, if any, sizable or even smaller packages in Giddings that are operated by public companies, just to set that straight. In this environment, what may happen is that bigger packages may be sort of holdouts for live to fight another day or live to see a better day, if you will, on product prices, oil prices before considering a sale. And smaller things may be more reasonable as far as connectivity and alignment between a buyer and a seller because the seller may run out of patience or money or whatever.

And those are small things, and they may just ultimately pop up somewhere else at the end of the day. So that smaller things may be more easy to move. I can’t guarantee that, but certainly a better chance at that than a larger thing as prices come down because the bid and the ask just widen apart between the players. Broadly, in South Texas, I would tell you that, look, everything is getting generally gassier. GORs are rising and the quality is waning. There are pockets of things here and there, but I would characterize it as generally over time, gassier; generally over time, somewhat scattered and maybe less synergistic opportunities. On occasion, you’ll find a private player who’s done a good job. But true to form, many private equity backed players will press on the accelerator to push activity and volumes in order to create more cash and [ EBITDA ] to try to sell an asset.

That typically doesn’t work very well for a public buyer to acquire somebody else’s declined rate while they run through the better part of their inventory. So that’s sort of how I would just characterize things generally.

Charles Meade: Got it. And then a question about your — I guess, your flexibility around your activity levels. When I look at — you guys have been really steady at 2 rigs, 1 frac fleet. But at least from the outside looking in, it looks like if you were to have to drop from there, you’re kind of sitting right above the minimum efficient threshold of keeping 1 frac crew pretty much continuously busy. So, is that something that you guys think about? And is that something that you — I mean, do you agree that it would be the case that you’d lose some efficiency if you had to cut activity in response to lower commodity prices? And how would you manage that?

Christopher Stavros: Not really. I’m not all that worried about it. We have very strong relationships with the crews and equipment that we use. I don’t see our activity pulling back dramatically in this environment, if at all. We could certainly adapt and do some things. From an efficiency standpoint, I’m not all that worried about it. We’ve entered into some contracts that give us quite a bit of flexibility to take advantage of some softness in pricing that we’ve seen recently, but at the same time, not so long as to take us out of play and considering things that — if things should worsen in the market to take advantage of that later on. So, I’m not very worried about it.

Operator: The next question comes from Peyton Dorne from UBS.

Peyton Dorne: I know earlier you gave the indications on the 2026 budget. But I just wonder if you have any details to share on how the plan theoretically might be shaped. And I ask just because you’ve highlighted the 6 well deferrals and maybe targeting completions to benefit from higher winter gas prices. So, we just infer from that, that maybe the spending is going to be a bit more weighted to the first half or first quarter ’26.

Christopher Stavros: Yes, thanks for the question. I would say generally, and this is probably not maybe very different from any in the industry, the spending levels will probably be a little bit more skewed to the earlier part of the year, which will include some test areas and also just because we have a little bit more line of sight on pricing sooner and we’ll pull forward some activity and volumes into the first half, first quarter of the year. So, if I had to skew it that way, I would say it will be a subtle heavier amount of activity and capital in the early part of the year, but not a dramatic difference, say, from 1Q to the back half. I mean on a percentage basis, it wouldn’t look that way. It will be more subtle.

Operator: The next question comes from Phillips Johnston from Capital One Securities.

Phillips Johnston: First question is on oil volumes. Chris, I think your comments on the second quarter call suggested that oil production should grow in ’26 at a rate that’s a little bit below the mid-single-digit target for total BOE production. Is that still a good way to think about next year, which I think would sort of put you somewhere in the 40,000 to 41,000 a day range, give or take?

Christopher Stavros: Yes, that’s sort of what I would think. I mean, like I said, the fourth quarter is off to a very strong start. I anticipate sort of record volumes, BOEs, but also oil in the fourth quarter. If I had to frame it, I would say, clearly, the record was earlier in the second quarter. So, we did 40,000 a day of oil. So, if I added gas, you’d sort of be at — 40,000 to 41,000 is a fair number. I would expect lower single-digit oil growth year-on-year full year ’26 over full year ’25, call it, 2% to 3%.

Phillips Johnston: Okay. Perfect. And then, for modeling purposes, if we assume you sort of remain at this current 2-rig program throughout next year, would that still imply somewhere around 55 gross wells next year? Or has the annual run rate continued to sort of creep up some with the efficiencies?

Christopher Stavros: Yes. I think plus or minus, that’s about right. It’s not a dramatic shift or change in the number of actual gross wells.

Operator: The next question comes from Zach Parham from JPMorgan.

Zachary Parham: You exited the quarter with the most cash on the balance sheet you’ve had since 1Q ’24. Obviously, that’s a great problem to have. But how do you think about use of that cash? If you continue to build cash, do you consider potentially increasing your buyback pace?

Christopher Stavros: Well, the goal is not only to generate free cash. It’s ultimately, to your point, really find a way to put it back into the business or utilize it to generate more returns over time, properly allocate it. We’ll just have to see how things move out or transpire into the — late into the year and into next year as far as the business. And I don’t — we’re not going to sort of amp up activity, if you will, to reach for more volumes necessarily. That’s not the point. The point is to look for pockets of maybe underperformance or disruptions in the equity. And if we have the opportunity to buy more shares, sure, we’ll do that. Or if we had the — and the shares that we repurchase actually, conveniently work in our favor and with the model in terms of providing us with a little bit of advantage on the base dividend.

So, it just means we can grow per share amount of the dividend a little bit more as a result of buying the shares and have less cash outlay that way. So, it does provide us with a lot of flexibility, Zach. And I think we’ll just sort of wait and see and take a lot of things into consideration on all those aspects of cash returned to the shareholders and even ultimately into looking at some bolt-on opportunities if they come along and if we can find something that’s attractive and the right fit for the business.

Zachary Parham: And then my follow-up, just wanted to ask on OpEx. You guided to $520 per BOE for LOE in 4Q. Can you just give some color on how you expect that to trend into 2026? I know you’ve done a lot of work this year to try to bring that down.

Christopher Stavros: Yes. I think as I mentioned in my comments, I think that there are some things that we’re looking at in terms of saltwater disposal, managing chemicals, fluid management generally, managing our crews in the field somewhat more efficiently. So, I think there’s — so far, we’ve had a lot of small wins and improvements in several areas. And I think some of that will stay with us. But in particular, as you know, workovers continue to represent the largest variability in the field level operating costs from quarter-to-quarter. But we’re doing some good work, I think, on surface facility expenses and other things in terms of moving around both oil and gas. And I think that should generally help us. So, I said $520 for the fourth quarter.

Seasonally, you start to — you pick up a little bit in the year seasonally into the first quarter. But once you get through that, I think you can come down a little bit from the $520 level into next year, I believe, at sort of current commodity prices.

Operator: The next question comes from Tim Moore from Clear Street.

Tim Moore: Congrats on the great free cash flow and execution. One of the questions I have for you, Chris, or maybe even Brian, is how should we think about the gathering, transportation and processing expense going forward as a percentage of revenue? I know you commented earlier this year about maybe up-ticking a bit. Oil price came down, that doesn’t help. But are there any kind of drivers you can speak to that maybe give a little bit utilization benefit for it maybe next year if the current commodity prices hold up?

Brian Corales: GP&T, I think you’re referring to it. It’s not really a percent of revenue generally. I’m sorry, it’s not — when you look at, it should be relatively — as long as commodity prices are somewhat stable, it should be relatively stable. If you see increases in gas and NGL pricing, you could see that cost go higher. And on the flip side, if commodity prices, gas and NGLs go lower, you may see some savings there.

Tim Moore: That’s helpful. And then just a follow-up. I know Chris already gave some comment on some of the improved efficiencies with water disposal, fluid handling, some of the chemicals. I was just wondering, if you’re working on Giddings very well and getting some efficiencies. Are there any other kind of surface repairs or low-hanging fruit there? Or do you think it’s mostly done in seventh inning?

Christopher Stavros: There’s always going to be some things that we continue to look at in terms of process management and doing things better. So, it’s really never over. You’re always turning over rocks and looking for other things to create more and more efficiencies over time, whether it’s with personnel, crews, moving things — the business of moving things in many ways. And so, moving and managing equipment — moving and managing your products. So, there’s always things to pursue beyond just what I mentioned.

Operator: The next question comes from [ Phil Shen ] from ROTH Capital.

Unknown Analyst: So, my first question is about the Giddings expansions. So, in the last quarter, we know that we expand by 40,000 acres. So, I’m just wondering like if any new wells were drilled in the areas? And also if not, like do you expect any potential expansion or any new wells in the future in that area?

Christopher Stavros: Yes. If you’re — thanks for the question. If you’re referring to some of the wells that we’ve drilled earlier this year and even late last year and a new area that provided us with quite a bit of the outperformance that we experienced, the answer is yes. We do plan to go back there. Those wells are continuing to perform quite good and continue to outperform with time. We will plan to go back there next year and over time in the future. There’s more to go after there, and I expect it to be folded into the program partly into next year and beyond.

Unknown Analyst: And my second question would be about the Eagle Ford production. So, I saw that the production from Eagle Ford was a bit up this quarter. So, I was wondering, was like any wells drilled in the quarter? If so, how was the performance for the wells?

Christopher Stavros: I assume you’re talking about the Karnes area. Look, we go to Karnes a couple of times a year. And again, we have one completion crew. So, you will see some — little bit of volatility just in terms of Karnes production. So, I think you can probably assume that if there was an increase, there was probably a little bit of activity, whether operated or non-operated.

Operator: The next question comes from Noah Hungness from Bank of America.

Noah Hungness: For my first question here, Chris, I was wondering how are you seeing service pricing right now? And how do you see that — and do you think it’s aligned with kind of where the curve is for oil prices?

Christopher Stavros: Thanks for the question, Noah. Yes. Look, I mean, things have come down into — throughout the better part of 2025, conditions are still relatively soft, but I think the rate of change has lessened here recently for us, and probably for the sector, for the industry, for us, I mean, I would tell you, we’re obviously going to see some things on the OCTG side still that’s tariff related that will have some underlying upside pressure. Most, if not all of that, really probably all of that will be offset by the softness that we’re seeing and the improvements that we’re seeing, that combination of some of our own efficiencies, but also some of the savings that we’re getting out of contractual arrangements and working with our vendors.

So there still is some softness, but I would tell you that for the moment in this range of product prices, things have — seem to have found a bit of a leveling out, if you will. That’s not to say that that couldn’t change if product prices were to turn south late this year or into next year. Typically, what’s underpinning some of that is the industry sort of prepping itself for more activity into — early into the new year. And so, some of that is seasonal. If that were to dissipate or as it dissipates into ’26, you could see some further round of softness perhaps, but we’ll see. It remains to be seen.

Noah Hungness: That’s really helpful. And then for my second question, could you — I know you have the 6 deferred completions that you’ll be carrying into ’26. But could you maybe talk about how many DUCs that you’re carrying into the new year? And then also how many DUCs you think you’ll be exiting 2026 with?

Christopher Stavros: We — generally, no, we don’t really carry planned DUC like DUCs. That’s why, I guess, we talked about the deferral of some of these earlier this year. But outside of kind of work in process wells, we don’t really plan to — we don’t usually carry DUCs.

Brian Corales: We’re not purposefully carrying DUCs. I mean it’s really more — it will end up being more of a timing issue than anything else.

Noah Hungness: Okay. So, would it be fair to assume you’re carrying the 6 deferred completions into ’26, but then you’d be exiting with basically 0 deferred completions with the current plan?

Christopher Stavros: Right. Outside of wells that are kind of in process, correct. [ No more ] DUCs.

Operator: The next question comes from Greta Drefke from Goldman Sachs.

Margaret Drefke: I actually wanted to follow up on the last one that was just asked there on your outlook for activity and the macro a little bit. In a situation of a potentially derating in oil prices through the remainder of the year or into 2026, can you provide any color around what price potentially could you see some incremental deferred completions or activity adjustments? Or if you have any sort of framework for how you could evaluate potential further completions or turnaround timing changes?

Brian Corales: Yes. I mean our program, it’s not a static program. It’s a dynamic program. And we have, as I mentioned in my remarks and in response to the questions, I mean, we have a lot of both financial and operational flexibility, especially considering some of those deferrals that have snaked through the system in 2025. As I said, that’s really provided us with a bit of a cushion, if you will, into 2026. That’s a sizable benefit. Look, if we continue to see some good performance as we exit the year and going into ’26, that could provide us with further cushioning and the ability for additional flexibility to respond to odd movements in product prices if that were to occur. But overriding that, we do have sort of the business model governor of our spending, which sort of limits us to the 55%.

We try to stay true to form to that and keep to that plan because that does keep us honest and straight narrow. But like I said, we have a lot of flexibility in the program to maneuver around product prices. I’m very comfortable with how the business is running right now and where we sit. So, there’s lots of capabilities that we’ve built into that process. So, you can look at the sensitivities for oil and gas prices and model it out as to what the downside-upside is, if you will. But I mean, generally — right now, at current prices, I’m not concerned about where we are.

Margaret Drefke: Great. And then just as a follow-up, as you highlighted in your update, Magnolia’s 2-rig 1-crew program over the past several years has supported about 50% production growth over that period of time. I was just curious; can you speak a bit about how much of that growth you view is attributable to improved rig and crew cycle time efficiencies versus acquisitions and versus well performance improvements potentially over the past few years?

Christopher Stavros: Yes. We’ve not acquired very much in the way of production over the 7 years we’ve been operating. I mean most of it has been maybe 1 or 2 transactions that provide us with any measurable amount of volumes that we can speak to. But most of it has been done organically. So, we probably produced over the — on a compounded basis, maybe 8% sort of compound annual growth for the business. By and large, most of that has come from organic drilling completions of the business, not — we haven’t folded in a lot of PDP that I can speak to.

Operator: This concludes our question-and-answer session and the conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.