Magnolia Oil and Gas (MGY) Earnings Transcript

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Date

Thursday, October 30, 2025 at 11 a.m. ET

Call participants

Chief Executive Officer — Christopher Stavros

Chief Financial Officer — Brian Corales

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Takeaways

Total production -- 100,500 barrels of oil equivalent per day for Q3 2025, representing 11% year-over-year growth and a quarterly record.

Adjusted EBITDAX -- Adjusted EBITDAX for the third quarter was $219 million, with a 31% operating income margin.

Free cash flow -- $134 million of free cash flow, driven by disciplined capital spending and production efficiency.

Capital reinvestment rate -- 54% of adjusted EBITDAX, reflecting a conservative approach to spending.

Shareholder returns -- $80 million was returned to shareholders, equal to 60% of free cash flow, distributed via repurchasing more than 2.1 million shares and paying cash dividends.

Cash balance -- $280 million at quarter end, highest level in 2025, after $65 million in bolt-on acquisitions during 2025.

Annualized dividend -- $0.60 per share annualized dividend payout rate, following a 15% increase, with the next $0.15 per share dividend payable December 1.

Weighted average diluted shares -- 190.3 million shares, down about 2 million sequentially and projected to fall to 189 million for 2025.

Liquidity -- Total liquidity was approximately $730 million as of Q3 2025, combining $280 million cash and an undrawn $450 million revolver.

Total revenue per BOE -- Total revenue per BOE declined approximately 12% year over year, due to lower oil prices partially offset by higher natural gas prices.

Adjusted cash operating costs -- $11.36 per BOE (adjusted cash operating costs, including G&A, for 2025), including general and administrative expenses.

Lease operating expenses (LOE) -- $5.20 per BOE expected for Q4 2025, with initiatives targeting ongoing reductions through operational improvements.

Production guidance -- Total production for Q4 2025 estimated at 101,000 BOE/day, expected to be a new record.

Full-year production growth outlook -- Full-year 2025 production growth outlook revised to approximately 10%, above original guidance of 5%-7%.

Capital spending outlook -- $110 million expected for Q4 2025, with total capital for the year at the midpoint of the reduced annual budget.

Price differentials -- An anticipated $3 per barrel discount to Magellan East Houston for oil sales in Q4 2025.

Hedging position -- Magnolia remains fully unhedged on oil and natural gas production.

Tax rate -- Expected effective tax rate of 21% for full year 2025, with zero cash taxes projected for the year due to new legislation.

Well deferrals -- Completion of several wells deferred into 2026, supporting reduced capital spending by roughly 5% in 2025.

2026 program outlook -- Capital spending to remain at 55% of adjusted EBITDAX in 2026; two drilling rigs and one completion crew planned, with mid-single-digit production growth anticipated if current prices persist.

Summary

Management communicated that Magnolia Oil & Gas (NYSE:MGY) achieved record production efficiency and financial results in Q3 2025, despite commodity price pressures, citing outperformance in the Giddings asset and operational cost reductions as driving factors. The board reaffirmed strict adherence to a capped capital reinvestment strategy, noting deferred well completions as a lever for both spending discipline this year and flexibility next year. Magnolia's full-year production growth guidance was raised above original targets, reflecting realized operational improvements, while shareholder returns remain a core priority, evidenced by consistent dividend growth and ongoing share repurchases. The company maintained a strong liquidity position and confirmed that no additional hedging would be implemented, emphasizing an unhedged policy on all oil and gas volumes. Management provided detail that bolt-on acquisitions completed year-to-date were relatively small and additive rather than transformative, and that large acquisition activity remains unlikely in the near term due to a lack of suitable opportunities matching strict strategic criteria.

Stavros clarified, "we have a lot of both financial and operational flexibility, especially considering some of those deferrals that have snaked through the system in 2025," indicating readiness for further adaptation if commodity prices weaken.

Corales stated that bolt-on acquisitions for Q3 2025 totaled $25 million, with a cumulative $65 million in bolt-on acquisitions during the year, mainly adding acreage, working interest, and royalties.

The executive team reiterated that dividend growth and share buybacks remain "mainstays" according to Christopher Stavros of Magnolia's ongoing value proposition.

Stavros emphasized that any future expansion in capital allocation or activity will remain subordinate to maintaining consistency in free cash flow returns and per-share value accretion.

Management expressed no intention to alter rig count or accelerate completion activity based on short-term price swings, underscoring strict capital discipline and long-term focus.

Industry glossary

EBITDAX: Earnings before interest, taxes, depreciation, depletion, amortization, and exploration expenses, commonly used in the upstream oil and gas industry to assess operational cash flow before exploration spend.

BOE: Barrels of oil equivalent, a standardized energy unit combining oil, natural gas, and natural gas liquids volumes for comparison purposes.

LOE: Lease operating expenses, the direct costs incurred to operate and maintain oil and gas wells.

D&C: Drilling and completion, referring to capital expenditures required to drill new wells and bring them into production.

DUC: Drilled but uncompleted well, a well that has been drilled but not yet completed or brought into production.

GOR: Gas-to-oil ratio, indicating the volume of natural gas produced relative to oil from a well or field.

PDP: Proved developed producing reserves, referring to oil and gas reserves that are both proven and currently in production.

GP&T: Gathering, processing, and transportation, referring to midstream service costs related to moving oil and gas from the field to market.

Full Conference Call Transcript

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. 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, one that has 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 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 repurchase. We continue to enhance and expand our asset base through bolt-on acquisitions stemming from our accumulated 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. All that said, and turning to Slide three 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 at quarters 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 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 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 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 and 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 mainstays 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 two drilling rigs and one 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 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 seven 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 will 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 2025 before turning it over for questions. Beginning on Slide five, 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 six. 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 towards 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 seven, this chart illustrates the progress in reducing our total outstanding shares since we began our repurchase program in the '20. At 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 quarter.

We currently have 5.2 million shares remaining under our repurchase authorization, which are specifically directed toward repurchasing Class A shares in the open market. Turning to Slide eight, 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 nine. Looking at Slide 10 and looking at our per-unit cash cost 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 and A, were $11.36 per BOE in 2025. 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 and 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-operated capital that is similar to that of 2024. We are reiterating our full-year 2020 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 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 zero cash taxes for the full year 2025. We are now ready to take your questions.

Operator: We will now begin the question and answer session. Please pick up your handset before pressing the keys. The first question comes from Neal Dingmann from William Blair. Please go ahead.

Neal Dingmann: Good morning, guys. 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 continues at the pace that we've seen driven by these Giddings wells could you envision, I mean, again, I think about when you keep would you accelerate production potentially even more than 10%? Would you be able to would you think more so about you'd even be able to cut CapEx? I'm just wondering when you toggle those two and if you keep having the same upside where can we see those benefits lie next year?

Christopher Stavros: Neal, 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 of 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 and realized efficiencies. I'm very confident of that. We've seen it. There's a litany of things that I could tell you that they're the teams are working on. That they currently see rather than I could spend twenty 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 love that you'd be able to do that. And then just lastly, you look at M and A, you guys have been doing a fantastic job of replacing your more than replacing your inventory. 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 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. Is there 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 add 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 email or 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 ship 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 it that white in that white space if it can be had. So we'll continue to do some of those things.

Neal Dingmann: Well said. Thank you. Again, nice quarter.

Christopher Stavros: Thanks.

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

Tim Rezvan: Good morning, Thank you for taking my question. 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 its last legs. It's 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, 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 dairy 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 think 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 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 lease. The question is always when you do these appraisal things, are 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. Okay. I Guess We'll Have To Stay Tuned Into Next Year. Yes. 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 acreage line. I'd be shocked, think, if you did some appraisal drilling there.

But is there discussion at the Board level about trying to understand if you think you have that resource? And do you have the deep rights? Thank you.

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 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.

Tim Rezvan: Okay. Thank you.

Christopher Stavros: Thanks.

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

Carlos Escalante: Yes. Thank you. Hey guys, thank you for taking my questions. 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 you could pull Because at your current adjusted EBITDAX cap on 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 barrel fifty dollars per barrel WTI.

Wonder if you can frame the appraisal program in the context of those levers. And again in the event of a sustained oil weakness? Thank you.

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, 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 will continue to examine different parts of it and try to high grade the program if you will.

Carlos Escalante: Wonderful. Thank you. Appreciate that Chris. And then on my follow-up I think that you certainly to us at least from a vantage point, one of the many sell points that Magnolia has in the 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've seen the 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 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, etcetera. 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 I'm not necessarily willing to lean in make something fully deterministic on somebody's view, because there's just so many moving parts.

Carlos Escalante: Wonderful. Thank you, Chris.

Christopher Stavros: Thanks.

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

Charles Meade: Good morning, Chris, Brian and the rest of the Magnolia team there. Good morning. Chris, yes, I'd like to go back to the A and D market and ask a question there. Can you offer your view have you seen anything different on packages that you look at around getting 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 getting specifically or just South Texas inclusive of the entire trend?

Charles Meade: I was asking more specifically about getting but I'd be curious to hear whatever views you want to share on the whole kind of Eagle Ford awesome Austin Chalk trend if you'd care to. 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 and 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 Lyft to fight another day or Lyft to see a better day if you will on product prices, oil prices before considering a sale. And smaller things maybe 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 in the ask just widen apart. Between the players. Broadly, in South Texas, I would tell you that look everything's getting generally gaffier 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 player back 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 does work very well for a public buyer. To acquire somebody else's decline rate while they run through the better part of their inventory. Inventory. So that's sort of how I would just characterize things generally.

Charles Meade: Got it. Thank you for that. 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 two rigs, one frac fleet. But at least from the outside looking in, looks like if you were to have dropped from there, you're kind of sitting right above the minimum efficient threshold of keeping one frac crew pretty much continuously busy. So is that something that you guys think about?

And is that something that you've 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 in how would you manage that?

Christopher Stavros: Not real. 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.

Charles Meade: Great. Thanks for the color.

Christopher Stavros: Thanks.

Operator: The next question comes from Peyton Doorn from UBS. Please go ahead.

Peyton Rogers Dorne: Hey, good morning, Chris and team. 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 asked just because you've highlighted those six wall deferrals maybe targeting completions to benefit from higher winter gas prices. We just infer from that, that maybe the spending is going be a bit more weighted to the first half or first quarter twenty six. Thank you.

Christopher Stavros: Thanks for the question. I would say generally and this is probably not maybe very different from any in industry. The spending levels would probably be a little bit more skewed to the earlier part of the year. To 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 in volumes into the first half, first quarter of the year. So that is skew it that way, I would say it will be a subtle heavier amount of activity in capital in the in the early part of the year.

But not a dramatic difference say from 1Q to or the back half. I mean on a percentage basis, it wouldn't look that way. It will be more subtle.

Peyton Rogers Dorne: All right. Great. Thanks for getting me on.

Christopher Stavros: Thank you.

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

Phillips Johnston: Hey, thanks for the time. First question is on oil volumes. Chris, I think your comments on the second quarter call suggested that oil production should grow in 2026 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 40 to $41,000 a day range. Give or take?

Christopher Stavros: Yes, that's sort of what I would 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. We did 40,000 a day of oil. So if I had to guess, you sort of be at 40% to 41% is a fair number. I would expect lower single-digit oil growth year on year full year 2026 over full year 2025 call it 2% to 3%.

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

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

Phillips Johnston: Okay, great. Thanks, Chris.

Christopher Stavros: Thank you.

Operator: The next question comes from Zach Parham from JPMorgan. Please go ahead.

Zachary Parham: Hey, thanks for taking my question. Sure. You exited the quarter with the most cash on the balance sheet you've had since 1Q 2024. 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 case? Well, the goal is not only to generate free cash. It's ultimately to your point really find a way 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 had the opportunity to buy more shares, sure, we'll do that. Or if we had the and the shares that we repurchased 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 the 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 returns to 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: Thanks, Chris. And then my follow-up, just wanted to ask on OpEx. You got into $5.20 per BOE for LOE in 4Q. You just give us 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 $5.20 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 and come down a little bit from the $5.20 level into next year I believe at sort of current commodity prices.

Zachary Parham: Thanks.

Christopher Stavros: Thank you.

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

Tim Moore: Thanks and congrats on a 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 early this year about maybe up ticking a bit, oil price came down, it doesn't help. But are there any kind of drivers you can speak to that maybe get a little bit utilization benefit for it maybe next year the current commodity prices hold up? GP and T, I think you're referring to is 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, you're working on getting 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. It's a 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.

Tim Moore: Great. Thanks Chris and Brian. All my other questions were already answered. Thank you.

Operator: The next question comes from Phu Pham from Capital. Please go ahead.

Phu Pham: Hi, thanks for taking my question. So my first question is that about the heating expansions. So in the last quarter, we know that we expand by 40,000 acres. So I'm just saying wondering like if any new wells were drilled in the areas And also like, if not, like, do you expect any known potential expansion or any new wells in the future? In that area? Thanks.

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 There's more to go after there and I expect it to be folded into the program, partly into next year and beyond.

Phu Pham: And my second question would be about the Ecopet production. So I saw that the divergence on the Ecoport was a bit up this quarter. So I was wondering if like was a any wells drilled in the quarter If so, like, what was the performance of the wells?

Brian Corales: I assume you're talking about the Karnes area. Look, go to Karnes a couple of times a year. Again, 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.

Phu Pham: All right. Thank you.

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

Noah B. Hungness: Good morning. 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, would tell you we're obviously going to see some things on the OCTG side.

Steel 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, a 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 seemed to have found a bit of a leveling out if you will. That's not to say 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 '26, you could see some further round of softness perhaps, but we'll see. It remains to be seen.

Noah B. Hungness: That's really helpful. And then for my second question, could you I know you're I know you have the six deferred completions that will be carrying 26, but could you maybe talk about how many DUCs that you're carrying into the New Year? And then also how many docs you think you'll be exiting at twenty six with?

Brian Corales: Generally know, we don't really carry planned doc like ducks. 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 docks. We're not purposefully carrying DUCs.

Christopher Stavros: Mean, it's really more it'll end up being more of a timing issue than anything else.

Noah B. Hungness: Okay. So would it be fair to assume you're carrying the six deferred completions in the 26, but then you'd be exiting with, base zero deferred completions with current plan?

Brian Corales: Right. Outside of wells that are kind of in process. Correct.

Noah B. Hungness: Okay. Normal DUCs.

Operator: The next question comes from Greta Drevke from Goldman Sachs. Please go ahead. Good morning and thank you for taking my questions. I actually wanted to on the last one that was just asked there on your outlook for activity in the macro a little bit. In the situation of a potentially de rating 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 turn in line timing changes?

Christopher Stavros: Yes. I mean our program is not it's not a static program. Dynamic program. And we have as I mentioned in my remarks and in response 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. 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 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 program to maneuver around product prices. I'm 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 mean it generally right now at current prices, I'm not concerned about where we are. Great. Thank you.

And then just for the follow-up, as you highlighted in your update, Magnolia's two rig one crew program over the past several years has supported about percent 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 seven years we've been operating I mean, of it has been maybe one or two 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 on compounded basis maybe 8% sort of compound annual growth for the business. By and large most of that is come from organic drilling completions of the business, not we haven't folded in a lot of PDP adds that we that I can speak to.

Greta Drevke: Great. Thank you. This concludes our question and answer session, and the conference has now concluded.

Christopher Stavros: Thank you for attending today's presentation. You may now disconnect.

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