Magnolia Oil & Gas Corporation Class A Stock

Good morning, everyone, and thank you for participating in Magnolia Oil & Gas Corporation's Second Quarter 2026 Earnings Conference Call. My name is Megan, and I will be your moderator for today's call. [Operator Instructions] The call is being recorded. I will now turn the call over to Magnolia's management for their prepared remarks, which will be followed by a brief question-and-answer session.

Thank you, Megan, and good morning, everyone. Welcome to Magnolia Oil & Gas' Second 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 second quarter 2026 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.

Thanks, Tom, and good morning, everyone. Thank you all for joining us today for a discussion of our second quarter 2026 financial and operating results. I know that today is a very busy day of earnings. I will briefly cover our second quarter results, which continue to validate the consistent high-quality nature of our Giddings asset and provide strong overall financial results, returns together with our Karnes area business.

I'll then highlight a few items related to the financing underlying our recent agreement to acquire WildFire Energy. Brian will then review our financial results for the second quarter in greater detail and provide some additional guidance before we take your questions.

Beginning on Slide 3 in our quarterly investor presentation, Magnolia marked its 8-year anniversary by delivering another quarter of strong and consistent execution as seen through our financial and operating metrics, which continue to underscore the strength of our differentiated business model and the quality of our asset base. Our strong second quarter financial metrics were supported by both solid production growth and higher year-over-year oil and NGL prices.

Our second quarter adjusted net income was approximately $184 million or $0.99 per diluted share with adjusted EBITDAX of $370 million during the period. Drilling and completion capital for the second quarter was $125 million with a reinvestment rate of just 34% of our adjusted EBITDAX and our lowest quarterly rate of capital reinvestment since 2022. Our pretax adjusted operating income margins averaged a very robust 51% for the quarter.

Magnolia generated $235 million of free cash flow in the second quarter and returned $80 million of this free cash to our shareholders through a combination of our base dividend and our share repurchase program where we bought back just over 1.7 million shares during the quarter. Our ongoing discipline around capital allocation, strong operational performance and continued focus on our financial returns allow us to generate meaningful free cash flow and to continue to execute on our proven business model.

For the second quarter of 2026, total company production volumes grew by 8% year-over-year to 106,100 barrels of oil equivalent per day, above our expectations and earlier guidance with oil production growing by 5% and averaging 41,900 barrels per day. Both total production and oil production volumes established new quarterly records for the company. Based on the strong second quarter production, we are raising Magnolia's stand-alone full year 2026 production growth guidance to 6% from 5%.

Production at Giddings continues to be the primary growth driver for Magnolia and setting a new quarterly record with total Giddings production increasing 10% year-over-year to 85,500 barrels of oil equivalent per day and oil production of 29,000 barrels per day with growth of 7% over the same period. Giddings production accounts for approximately 81% of Magnolia's total company volumes.

Production in our Karnes area was relatively flat year-over-year at just over 20,000 barrels of oil equivalent per day during the second quarter and which we expect to sustain for many years. The Karnes area assets continue to generate a significant amount of free cash flow for Magnolia.

Turning to Slide 4. As we announced last month, we entered into a definitive agreement to acquire WildFire Energy for a total consideration of approximately $4.06 billion. The acquisition will add approximately 810,000 net acres to Magnolia's Giddings area position and total oil and gas production of roughly 53,000 barrels of oil equivalent per day, including 37,000 barrels per day of oil. The acquisition of the WildFire oil and gas properties and acreage is a natural and strategic fit for Magnolia and greatly improves our business by extending our runway of advantaged profitability and the durability of our significant free cash flow generation.

This fit should be clear given the sizable overlap and with roughly 70% of Magnolia's existing acreage benefiting from the transaction with significantly more acreage benefiting from adjacency. Our combined position in the Giddings field will amount to more than 1.25 million net acres with upside development opportunities across multiple benches, including the Austin Chalk, Eagle Ford and Woodbine. The acquisition is a culmination of our extensive subsurface understanding, experience and the demonstration of our proven resource capture in the Giddings field.

This creates a premier upstream operation in South Texas by combining 2 high-quality and complementary assets near Gulf Coast markets, which offer premium pricing for our products. We expect the transaction to be immediately and highly accretive to our key per share financial metrics, including cash flow, free cash flow and earnings in addition to enhancing our D&C capital reinvestment rate.

WildFire is not only a strong fit for Magnolia, offering unique benefits, but it also provides several important characteristics we look for, namely focused high-quality assets with concentrated scale, a low capital reinvestment rate, the ability to provide moderate production growth with high operating margins and steady free cash flow, allowing for consistent and significant shareholder returns.

Following the WildFire announcement, Magnolia executed multiple capital markets transactions to partially fund the acquisition. Magnolia issued 53.3 million new shares in a public equity offering for net proceeds of $1.23 billion, in addition to $500 million of senior notes at a 6.625% coupon due in 2034. These 2 transactions closed on July 22 and August 5, respectively. In total, the WildFire acquisition will be funded with a balanced mix of approximately half equity and half debt with the acquisition on track and expected to close late in the third quarter.

Turning to Slide 5. One of the most important elements of the WildFire acquisition is that Magnolia's differentiated, proven and highly investable business model remains unchanged. While the acquisition adds more leverage than we have carried historically, we believe this is very manageable. Given the significant increase in our free cash flow generation, we have a clear line of sight towards the reduction of debt, which we expect to be less than 1x our net debt to EBITDA by year-end 2027, if not sooner, and returning us to our traditionally more conservative leverage profile.

As part of our disciplined capital plan, we will continue to limit our D&C spending to 55% of adjusted EBITDAX, which provides consistent free cash flow through the cycle while delivering both moderate annual total production growth and oil growth. With our combined oil production mix of approximately 50%, we expect to generate high pretax operating margins and in keeping with our business model, continue to return a significant portion of our free cash flow to our shareholders.

This includes a safe, sustainable and growing dividend, which is expected to compound at a rate of about 10% over the long term in addition to our ongoing share repurchases of at least 1% of the outstanding shares per quarter. I often mention that one of Magnolia's primary goals is to be the most efficient operator of our best-in-class oil and gas assets to generate the highest returns on those assets while spending the least amount of capital on drilling and completing wells.

The combination of Magnolia and WildFire creates a larger and stronger enterprise with a concentrated acreage position that offers moderate growth, best-in-class financial returns while generating significant free cash flow. Magnolia will continue to look and behave like it has historically with an emphasis on managing both operational and financial risk and using the same differentiated and proven business model to continuously compound value for our shareholders. As we were briefly restricted from share repurchases while working on the WildFire acquisition, we expect to resume our share repurchases after today's quarterly results.

I'll now turn the call over to Brian for further details on the quarter for some additional guidance.

Thanks, Chris, and good morning, everyone. I will review some items from our second quarter results and refer to the presentation slides found on our website. I'll also provide some additional guidance for the third quarter of 2026 before turning it over for questions.

Beginning on Slide 6, Magnolia delivered a strong quarter, generating adjusted net income of $184 million or $0.99 per diluted share. Our adjusted EBITDAX for the quarter was $370 million with total capital associated with drilling completions and associated facilities of $125 million, representing just 34% of our adjusted EBITDAX. Second quarter production volumes grew 8% year-over-year to 106,100 barrels of oil equivalent per day while generating free cash flow of $235 million. Our second quarter annualized return on capital employed was 39% as a result of higher prices and increased production.

Looking at the quarterly cash flow waterfall chart on Slide 7. We started the quarter with $124 million of cash. Cash flow from operations before changes in working capital was $362 million, with working capital changes and other small items impacting cash by $15 million. During the quarter, we paid dividends of $31 million and allocated $49 million towards share repurchases. We incurred $125 million in drilling completions and associated facilities and leasehold, and we ended the quarter with $296 million of cash, an increase of $172 million.

Looking at Slide 8. This chart illustrates the significant amount of share repurchases we have done since beginning the program in the second half of 2019. Since that time, we have repurchased 85.5 million shares. We repurchased just over 1.7 million shares during the quarter prior to being restricted due to the transaction, leading to the diluted weighted average shares outstanding of 184.6 million shares during the second quarter. We currently have 9.9 million shares remaining under our repurchase authorization.

Turning to Slide 9. Our dividend growth has grown substantially over the past few years, including a 10% increase announced early 2026, an additional 9% increase announced a couple of weeks ago in conjunction with our definitive agreement to acquire WildFire to $0.18 per share on a quarterly basis. Our next quarterly dividend is payable on September 1 and provides an annualized dividend payout rate of $0.72 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 strong balance sheet, and we ended the quarter with $296 million of cash. Our $400 million senior notes does not mature until 2032, and our recently closed offering of $500 million senior notes associated with the financing of the WildFire transaction matures in 2034. Upon closing, estimated late in the third quarter, we will also assume WildFire's $600 million senior notes due in 2029.

Also upon closing, our credit facility will increase to a $2 billion borrowing base with elected commitments of $1.75 billion, providing plenty of available liquidity. We thoughtfully financed the transaction with half equity and half debt, positioning Magnolia to have a very manageable debt load at the close of the transaction, allowing us to maintain our business model and our consistent return of capital program. With a significant increase to pro forma cash flows, our plan is to immediately begin to reduce our debt post closing of the transaction. Our condensed balance sheet as of June 30 is shown on Slide 10.

Turning to Slide 11 and looking at our per unit cash costs and operating income margins. Total revenue per BOE increased approximately 39% year-over-year due to the strength in oil prices. Our total adjusted cash operating costs, including G&A, were $11.55 per BOE in the second quarter of '26, and our adjusted operating income margin for the second quarter was $25.15 per BOE or 51% of our total revenue.

Turning to guidance. Third quarter D&C capital expenditures for Magnolia stand-alone is expected to be approximately $115 million. In addition, total production for the third quarter is estimated to be similar to second quarter levels or approximately 106,000 barrels of oil equivalent a day. Our full year 2026 outlook for total production growth has increased to approximately 6% from our prior guidance of 5%.

Oil realizations have trended back to our historical differentials, and we are anticipating prices for the third quarter to be a $3 per barrel discount to Magellan East Houston benchmark pricing. The fully diluted share count after closing the WildFire transaction is expected to be approximately 269 million shares. We expect our effective tax rate to be approximately 21% and cash taxes for 2026 to be minimal. We are now ready to take your questions.

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

This is Bert filling in. I know WildFire hasn't closed yet, but maybe you could give early thoughts on maybe what a blended D&C plan might look like. Last call, I think you mentioned you're picking up the rig -- 2 rigs and a crew. That might imply 50-50, but we've kind of looked at the data in Giddings on Enverus and that seems pretty strong. So it would be impressive for the new assets to kind of get equal screen time. Just any thoughts on how you would prioritize the 2 assets?

Yes. So if you just simplistically took what we have, what we've been doing and what they've been doing and combine it, that's not a bad starting point. So there's 2 rigs for each of us and 1 completion crew for each of us. It's still very early. We haven't closed. We'll have more information for you probably later at the back part of this year and after we close on the combined business and our activity.

I do believe that we can do better on a combined basis. We're obviously going through it. As I've always said, our emphasis is to do this as efficiently as possible. And I think we'll be able to do that. We know the field very well. We know the subsurface very well. We've got some very good vendors to work with and good crews, and we'll be evaluating theirs. And collectively, I do believe that on a combined basis, we'll be able to do better.

That makes perfect sense. And then on the capital allocation of your free cash flow, you kind of laid out the 5 pillars. We assume most of it will go towards debt. But is there a large opportunity to add working interest or I think you called it small bolt-ons? I just imagine there'd be some white space, but also that WildFire was probably out there buying up everything they could. So I just didn't know if there was anything left in the area? Or was that implying outside the kind of pro forma footprint?

No, I wouldn't tell you it's much outside the pro forma footprint. They did a very good job with line of sight and looking sort of over the hill, if you will, on needing to sort of pick up additional working interest as they were going ahead permitting wells and moving forward with drilling. So they did a little of that, certainly.

I do think that there are and will be opportunities for us to pick up additional working interest and royalties on a concentrated basis, if you will, here and there within the existing footprint of combined Magnolia-WildFire. So I don't think we'll be moving vastly out of that footprint. I think there's still plenty to work on.

These will be sort of the typical usual blocking and tackling smaller bolt-ons that we've done that will amount to smallish amounts of money outflow, if you will. I wouldn't tell you that there's anything very, very large by any means. So the money, the free cash flow in excess of our return of capital plan will go to the debt first and foremost. And then there's a little left over, we'll certainly be open to picking off some working interest and royalties to make us better and improve our capability.

That sounds like the right thing to do.

The next question comes from Phillip Jungwirth with BMO.

I wanted to come back to the Austin Chalk potential discussion for WildFire. Obviously, they mostly targeted the Lower Eagle Ford, but they do have some strong Chalk wells across the Robertson, Milam area, offsetting you even in Washington and also Eastern Brazos County. But just wondering which of these areas do you think are more interesting? And could the Chalk potential also just be more widespread across the footprint than just the areas that they've tested?

You could be right. We'll certainly give it our best shot and try to figure that out. This is an enormous footprint, obviously, 1.25 million net acres. So it's going to take us some time to work through. I think the areas that you identified are correct in addition to areas in Burleson. So no, there's a tremendous amount of potential upside.

There has been up to now vis-a-vis WildFire sort of limited testing drilling. So I think there's a lot of low-hanging fruit, if you will, that will be accumulated under Magnolia's experience and expertise and just technical knowledge, and we'll get at it over time into next year and beyond and continue adding to it. So there's lots -- there'll be lots to work on. To some extent, our folks are going to feel like kids in a candy store. So there'll be lots to work on.

Sounds good. And then can you talk about the acquired sand mine and the benefits here? Just are you able to quantify well cost savings from the vertical integration and any optionality it provides you on completion design for both WildFire and legacy Magnolia?

Yes, we didn't actually quantify it or break out the specific savings for the sand mine. But I would tell you, in aggregate, it's several million dollars of the synergies and cost saving benefits that will get captured in the process. So that's something different for us owning a sand mine. But clearly, we were sourcing and are sourcing most of the large majority of our sand requirements and demand from that mine. So it's important to us, and they've done a good job running it. So it will be meaningful in the outcome in terms of what we're able to do going forward.

The next question comes from Carlos Escalante with Wolfe.

My question is around how should we think about the trajectory of what you developed the next 12 months? Said more explicitly, knowing that WildFire was more of an Eagle Ford developer and you're more of an Austin Chalk developer. What do you think it's a good placeholder for us modeling the company to have for the next 12 months? Is it a transition from Eagle Ford at first on to Austin Chalk? Or should we expect a more equivalent development in between both?

I think -- no, I know the plan will be roughly a decent -- roughly even mix of Eagle Ford and Chalk. And that's not to say that there's anything -- any issue one way or the other. It's just sort of that -- we'll probably initially have that balanced plan. And actually, that's an uplift if you want to think about where they will be coming from on their Austin Chalk activity to where we're going to take it because we think there's a lot more to capture there and given our expertise and experience, obviously.

The benefit of the Eagle Ford for us in the transition is the fact that it's generally been done for many years there by -- not just by WildFire, but by previous operators. And so there's a lot of consistent operational experience and expertise, if you want to say that. And so we'll be looking at ways they've done things and to see if we can employ our model on top of that to see if there's any improvements. I think -- frankly, I think there will be just in terms of how we drill and complete, maybe even more so maybe drill. But I would tell you that the cadence will be fairly even between the 2, but that would represent an uplift on the Chalk D&C in activity relative to what they have been doing.

Got it. Fair enough. And then the deal carries a significant amount of oil leverage on their assets relative to where Magnolia stood at a corporate level. So I wonder because Karnes has usually been a source of that exposure to oil. If you can frame today's Karnes strategic fit to you in light of that?

Yes, sure. I mean as I mentioned in my remarks, the Karnes asset, we're very confident that we can hold that flat for many years and given some recent acquisitions that we've done to sort of bolster the available upside of development there. So we like the asset. It generates an enormous amount of free cash flow. So it really is sort of a cash cow, if you will.

The way I would characterize it is it does provide ballast and stability for the overall organization. So it's a very important element of what we are and for the business model going forward. We like Karnes. It's a good asset. It's a very high-quality rock. And there's probably more things down the road there given the quality of subsurface that we've not yet gotten to and will over time.

The next question comes from Peyton Dorne with UBS.

I wondered if you could walk through the mechanics of the buyback a bit here for 3Q. Chris, it sounds like first from your comments that the restrictions are now over, so you'll be back in the market. Are there any restrictions on the repurchases as we get closer to the deal close or any other nuances that we should be thinking about this quarter on the buyback?

No. We've pretty much at this point, we're moving to close. We've pretty much disclosed everything that we need to and are required to disclose. So we're not in any -- we don't have any material nonpublic information. So we're open to repurchasing. We're going to get at that ASAP. And to the extent that the stock doesn't perform the way we believe it should or reflects the benefits of the transaction, we will choose to be potentially more aggressive than not. So you should think that we'll be involved as soon as we can.

Great. That's helpful detail. And then if we could just go back to the capital allocation side. I'm just curious, when you think about the expected larger scale post-WildFire, if there's like a minimum type cash balance that you'd like to keep on hand on a go-forward basis. And I guess what I'm really trying to get to is how actively or aggressively you'll be kind of repaying that revolver once the deal closes?

Yes. I mean that will really be a priority for us getting that leverage and debt balance down quickly and fairly ratably. At current commodity prices, product prices, that will move ahead at a decent clip, and you'll see it -- we'll mark time there, giving, obviously, the financials every quarter, and you sort of see it, see the debt come down every period. And if we can find some extra money to put to it, we may do that. So it will be coming down at a good pace. I don't want to give too much in the way of specifics, but that will be a big focus. And I feel very confident that the 1x or less, like I said in my remarks, certainly by the end of next year, but frankly, probably sooner than that.

[Operator Instructions] Our next question comes from John Davenport with Johnson Rice.

I wanted to go -- focus on the production guidance increase from 5% to 6% year-over-year. I know much of that increase is from the Giddings acreage, actually, all of it is. Curious if that's simply just well outperformance of expectations so far, if you've made any changes on the D&C front that might be contributing to that?

No, there's nothing very meaningful in this particular period or in the last 3 to 6 months that I would tell you has been needle-moving on the D&C front in terms of the well performance. It's really just good operational outcome from the wells that we brought online in Giddings, as you mentioned. So that's exactly what I would point to. And importantly, this is all stand-alone Magnolia. So we've done better than we anticipated, and that program is sort of continuing that way. So it's very specifically the well performance.

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

Good morning, everyone, and thank you for participating in the Magnolia Oil & Gas to acquire WildFire Energy Call. My name is Betsy, and I will be your moderator for today's call. [Operator Instructions]. Our call is being recorded.

I would now like to turn the call over to Magnolia's management for their prepared remarks, which will be followed by a brief question-and-answer session.

Thank you, Betsy, and good morning, everyone. Welcome to Magnolia Oil & Gas' acquisition of WildFire Energy 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 the 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 11 of the conference call presentation with the supplemental data on our website. You can download the press release as well as the conference call slides from the Investors section of the company's website at www.magnoliaoilgas.com.

I will now turn the call over to Mr. Chris Stavros.

Thank you, Tom, and good morning, everyone. Thank you all for joining us early this morning as we're pleased to announce Magnolia's acquisition of WildFire Energy. I plan to discuss some of the beneficial aspects of the acquisition, including some higher-level details, and we'll be referring to the slide presentation that can be found on our website.

To begin with, I wanted to provide you with a brief background on Magnolia's history around M&A and remind you of our acquisition strategy. M&A is not foreign to us as we've looked at dozens of opportunities over the years and done more than $1 billion of transactions. Although these have primarily been small bolt-on deals, while the acquisition of WildFire is much larger, we would still characterize this as a bolt-on transaction. There is clear overlap with a natural, strategic fit and industrial logic supporting this deal as the WildFire acquisition more than doubles our existing acreage position in the Giddings field. And importantly, the acquisition is the culmination of our extensive subsurface experience, superior knowledge and the demonstration of our proven resource capture in Giddings over the past 8 years.

When considering any M&A at Magnolia, our standards are high, and we always ask ourselves whether the transaction will make us better. We also look for opportunities that have similar attractive operational and financial characteristics to our core assets and that can compete for capital with our existing assets. Finally, we target acquisitions that don't simply replace the oil and gas that has been produced, but also improve the resource opportunity set for the overall business.

On these points, we believe that the WildFire acquisition greatly enhances Magnolia's position by extending our runway of advantaged high-return profitability and significant free cash flow generation and creating the premier Eagle Ford, Austin Chalk operator with more than 1 million contiguous acres in South Texas.

Starting on Slide 2 in the presentation slides and noting some specific details of the transaction, we've agreed to acquire WildFire Energy for approximately $4.06 billion to be funded with a balanced mix of cash and equity, including 32.2 million shares of Magnolia Class A Common Stock to be issued to the WildFire owners, and we are also assuming WildFire's $600 million of outstanding notes due in 2029. Magnolia intends to fund the remaining amount through a combination of cash on hand and a balanced mix of debt and new common equity.

Magnolia has obtained committed financing in connection with this transaction and has amended and increased the company's secured credit facility to a $2 billion borrowing base and with elected commitments of $1.75 billion contingent upon closing the transaction. The transaction effectively consolidates most of the Giddings field in area, adding roughly 810,000 net acres, resulting in a Magnolia Pro Forma acreage position of nearly 1.3 million net acres over 1.5 million gross acres. Shown in the map on the right side of the slide, given the overlap, it should be clear that the WildFire assets are a natural, strategic fit for Magnolia. Helped by the combination of our deep technical understanding of Giddings and our strong balance sheet, this puts us in a unique position to opportunistically pursue a large and highly attractive asset in our own backyard.

This acquisition brings together 2 high-quality and complementary assets near Gulf Coast markets, which offer premium pricing for our products and enables us to extract annual cost savings and value-added synergies of at least $100 million by the end of next year. In addition, the transaction will benefit almost 70% of Magnolia's existing acreage through higher working interest, which is an unmatched level of overlapping position together with a significant amount of adjacent acreage. The WildFire assets produced approximately 53,000 barrels of oil equivalent per day, including 37,000 barrels per day of oil production during the second quarter of 2026. Total combined Magnolia Pro Forma production for the second quarter was 159,000 barrels of oil equivalent per day, including 79,000 barrels of oil per day with an oil mix of about 50%. A key advantage of WildFire's production is its low base decline rate, which we estimate to be approximately 29%. The transaction is expected to be highly accretive to all of Magnolia's key financial metrics, including cash flow and free cash flow per share, operating margins, earnings per share and NAV.

As a result of the sizable and expected increase in our free cash flow from the WildFire assets, we are raising our quarterly dividend by 9%. Magnolia's Board of Directors have unanimously approved the acquisition, and we anticipate closing to occur late in the third quarter of this year. Looking at Slide 3, one of the most important elements of the WildFire acquisition is that Magnolia's differentiated, proven and highly investable business model remains unchanged. Shown on the left side of this slide is our business model, our recipe, if you will, which is really the essence of what we're all about since our founding. This is largely an industrial type model, and we believe its application is critically important for increasing shareholder value.

The acquisition of WildFire helps further support our business model with its low oil decline rate, low capital reinvestment rate, high cash margins and the addition of significant high-quality resource opportunities. Maintaining conservative leverage has always been a key component of Magnolia's business model since our founding. Although our level of debt will initially increase to accommodate the acquisition, we view this as very manageable and more temporary given the sizable amount of free cash flow generation expected from the Pro Forma business. To minimize risk and provide us with greater financial flexibility and liquidity, our plan is to utilize most of our free cash flow generation in excess of the company's shareholder return program to immediately focus on swiftly and steadily reducing debt in keeping with Magnolia's conservative financial policy.

We fully expect to be at roughly 1x or less our net debt to EBITDA by year-end 2027, pursuing further debt reduction over time given our consistent free cash flow generation and as we capture additional synergies and capital efficiencies.

Like our current plan, we expect to limit our D&C capital spending to less than 55% of our annual adjusted EBITDAX. In combination with Magnolia's business, we expect WildFire's high-quality assets to help deliver moderate and mid-single-digit annual growth for both total production and our oil production on a pro forma basis, a rate of growth higher than most of our peers and with high pretax operating margins. Going forward, we expect both our total BOE production and our oil production to see similar rates of mid-single-digit growth. We expect to consistently return a significant portion of our free cash flow to shareholders, including our safe, sustainable and growing dividend, which I expect should grow over the long term at a compound rate of about 10% and is an outcome of the business. And we will continue with our share repurchases of at least 1% of our outstanding shares per quarter.

Shown on the right side of this slide are our capital allocation priorities. While I would expect us to continue with very small bolt-on acquisitions that fill in some minor gaps in acreage or that add incremental working interest or royalties to existing leases, any large-scale M&A or acquisitions are currently off the table and frankly, unnecessary.

Slide 4 highlights much of what I've discussed with the WildFire acquisition improving on Magnolia's operating unique operating platform by creating the dominant Eagle Ford and Austin Chalk E&P company in South Texas through the combination of 2 high-quality complementary contiguous assets in the Giddings field. We believe our unmatched knowledge of Austin Chalk and Eagle Ford development will continue to add resource optionality and duration from one of the largest, most concentrated resource positions close to advantageous Gulf Coast markets. We expect the acquired assets to improve on our industry-leading reinvestment economics, extending our sustainable free cash flow generation and a return of capital to shareholders.

Moving on to Slides 5 and 6. I've often shied away from using banker buzzwords such as size and scale and transformational as justifiable reasons for pursuing larger M&A, so I'll try to describe this transaction a bit differently. The WildFire acquisition is an ideal example of in-basin M&A with concentrated and high-quality acreage primarily focused in the Eagle Ford and Austin Chalk. On a Pro Forma basis, Magnolia's acreage position becomes the largest in South Texas Eagle Ford, Austin Chalk trend and nearly 1.3 million net acres and inclusive of our Karnes County area assets. As Slide 5 shows, Magnolia's position is almost 80% larger than the second place operator, highlighting the extensive potential resource base created by the acquisition to both execute on the existing inventory and appraise future development opportunities.

Magnolia's acreage position is not only larger, but also deeper with the acquisition adding another dimension of depth and upside development opportunities across multiple benches, including the Austin Chalk, Eagle Ford and Woodbine across the acreage. Slide 6 not only highlights the creation of a dominant acreage position in the Giddings Field, but also the substantial increase to Magnolia's oil production and proved developed reserve base. Our Pro Forma oil production increases by 89% to nearly 80,000 barrels per day, with our oil mix rising to 50% from roughly 40%. Our total proved developed reserves increases by 84% to more than 300 million barrels of oil equivalent, and our proved developed oil reserves increased by approximately 155% with the overall mix of proved developed oil reserves climbing to roughly 54%.

Turning to Slide 7. As I mentioned, given the large overlap with our assets, our own field operations experience in Giddings and our extensive technical knowledge of the subsurface, we believe that Magnolia is uniquely able to extract significant synergies from the WildFire acquisition. We expect the annual cost savings and synergy capture to be at least $100 million on a run rate basis by the end of 2027. We calculate the present value of these savings and efficiencies is approximately $700 million and with these improvements captured in 3 buckets, including drilling, completions and facilities, field operations and corporate G&A, with the approximate allocation by category at 60%, 20%, 20%, respectively. We anticipate seeing the earliest progress in the areas of corporate G&A and field operations with savings here likely to be near the full run rate by midyear 2027.

While the WildFire assets immediately improve Magnolia's D&C capital reinvestment rate, we expect to capture further D&C synergies and efficiencies under our development plan. Some of these additional benefits include a significant opportunity to extend the average lateral length of our wells, applying Magnolia's supply chain and logistics pricing to WildFire's historical practices, the sharing of facilities and infrastructure in the field and the application of Magnolia's drilling and completion technology and expertise towards the future development of Giddings, a capability we have proven after 8 years of successful operations.

An underappreciated aspect of the acquisition is the embedded infrastructure within the assets and the added benefits these provide. The WildFire assets also include approximately 500 miles of gas gathering pipelines in Giddings in addition to a local sand mine. The sand mine is strategically important as it currently supplies all of Magnolia's Giddings and WildFire's Frac sand consumption in addition to third-party sales. This provides a significant benefit in the cost of the sand we use in our Giddings development.

In addition, the overlapping and adjacent acreage positions are expected to reduce our operating expenses as we streamline our field operations. Taken together, these synergies represent some of the clear benefits of an in-basin acquisition with concentrated scale that are unique to Magnolia, helping to drive further value for shareholders. Lastly, to help seamlessly integrate the WildFire assets and operations, we've created an internal integration management office an IMO that will assist in our day 1 execution. We have also executed a transition services agreement with WildFire to assist in the integration. The overall goal of the IMO is to help plan and execute both pre- and post-closing goals to minimize any potential hiccups along the way. This was a model that we successfully deployed and implemented after the separation from EnerVest, and we will plan to put it back into action for this acquisition.

Looking at Slide 8, we expect the WildFire acquisition to generate significant levels of free cash flow supported by the high-quality assets, our disciplined capital program delivering moderate annual production growth, combined with meaningful cost savings and operational synergies. At recent strip prices, we estimate the combined business should generate more than $4.5 billion in cumulative free cash flow during the next 4.5 years through 2030. The significant free cash flow generation gives us confidence in providing a clear pathway to reduce debt while maintaining our strong return of capital program to shareholders aligned with Magnolia's business model.

Slide 9 shows our record of strong and consistent growth in our dividend since it was established in 2021. Our confidence in the high quality and capability of the WildFire assets and higher free cash flow generation supports improved shareholder returns, driving an immediate increase of 9% in our quarterly dividend to $0.18 per share payable in the third quarter of this year. This is also the second increase in our quarterly dividend this year following a 10% increase announced in January. We also expect to maintain our ongoing share repurchases of at least 1% of outstanding shares per quarter after closing the transaction.

Finally, on Slide 10, this shows the history of Magnolia's return of capital program since the company's inception 8 years ago. Over this period, we have returned approximately $2 billion to our shareholders or roughly 40% of our market value, an accomplishment we take pride in. Based on the strategic benefits of this acquisition and the anticipated strong and consistent free cash flow generation, we expect our durable track record of capital return to shareholders will endure as we execute the same proven business model that continues to compound value for our shareholders.

One final item before we take your questions. As noted in this morning's press release, Magnolia's second quarter total production averaged approximately 106,000 barrels of oil equivalent per day with oil production of roughly 42,000 barrels a day. D&C capital for the second quarter was $125 million, and the company ended the quarter with cash on the balance sheet of $296 million. Based on Magnolia's strong second quarter production, the company is increasing its full year 2026 annual production growth guidance for Magnolia on a stand-alone basis to 6% from 5% -- additional details on the impact of the WildFire acquisition to Magnolia's 2026 production and capital spending will be provided after closing, which is expected to occur late in the third quarter.

To wrap up, the WildFire acquisition is a classic case of having the opportunity to own more high-quality acreage and inventory in our own backyard that we know and understand well. Not only are these assets a hand in glove fit for Magnolia, but they also offer unmatched resource benefits while meeting several important characteristics we look for focused high-quality assets with concentrated scale, a low capital reinvestment rate, providing moderate annual total production growth and oil production growth with high operating margins and steady free cash flow, allowing for consistent and significant shareholder returns. And importantly, this allows Magnolia to continue to execute on its differentiated and successful business model. The combination of these 2 high-quality businesses improves our position for sustained growth, strengthens our financial returns and increases our dividend per share payout capacity, creating improved long-term value for our shareholders.

Thank you, and we're now ready to take your questions.

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

Chris and team, congrats on the deal. I'm sure it's been a long few days. But Chris, my question is on sort of upcoming activity. You mentioned in the Magnolia way you'll continue to spend less than that 55% EBITDAX. I think if I see right that WildFire was running a couple of rigs. I mean is the plan do you think would be still 2 plus 2 still going to equal 4 from an activity standpoint? Is there anything you can say on that yet?

Sure. Thanks, Neil. Immediately, we'll take on the 2 plus 1, as you mentioned, the 2 rigs, 1 completion crew, which will sort of double ourselves. We'll take a close look at this. I mean, just understand, and I would say this for any of the questions, we haven't closed the deal yet. So as I said, we'll close late in the third quarter. But as we get after this, we're going to be looking at achieving -- applying the technical capabilities that our team brings to the subsurface and also the supply chain aspects that I mentioned in the remarks.

We'll look at and see if we can do better. I believe we can do a touch better than this. But for initial purposes, we'll take on the 2 rigs and 1 completion crew. I don't want to get into too many specifics around the type of equipment or who, but I mean, you can imagine that there may be some things there as well.

Absolutely. And then just maybe in that same vein on activity. It seems like now with the combined, will you do a lot more multi-formational? I mean, again, when you attack it now, are you going to attack Eagle Ford, Chalk, I mean everything? Maybe talk about that because it seems like there's...

Everything. Yes, everything. We will be attacking everything. I would tell you, initially, the big mix, broad mix will be a fairly even and consistent mix of Chalk and Eagle Ford roughly with Woodbine maybe a little bit at a later stage, but we'll mix some of that in as well with time. But look, this is not going to be very different than what we've been doing from attacking it. I think the benefits are the low oil decline rate that they have in the Eagle Ford, the shallower nature of those wells and the lower cost of those wells.

So that's a really important aspect of the assets. So I think there, we can see some benefit in our capital program as well.

The next question comes from Peyton Dorne with UBS.

Within the acquisition, you obviously highlight the mention of WildFire sand mine and the gathering lines. I'm just curious, with more scale in Giddings, if you see an opportunity for some more kind of midstream or services integration beyond the mines and the pipes? And then broadly, how do you see yourself benefiting from more scale as this kind of embedded in that synergies target that you put out?

Well, I think I -- as far as more integration of infrastructure, I mean, it's coming with plenty. A lot of the gas gathering lines that I mentioned, obviously, the sand mine that you pointed out, -- the adjacency of the acreage and the overlap is, I think, one point to emphasize, if you will. So there's a lot of benefits that are going to come to us from, again, a word that I don't often like to use the scale -- the simple scale of this. It's massive, spanning probably 7, 8 counties at least. So as we wrap everything together, we'll continue to look for more with time.

But I think the percentage allocation of the synergies that I mentioned, the 60% to D&C and field operations and G&A getting 20% each, I think, sort of speaks to a lot of what the point is and what we think we can capture. But there's just a lot there, Peyton.

That's helpful to hear. We'll be interested to see how it all develops and unfolds.

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

Chris, I want to start on the resource base WildFire has. First off, it looks like about 99% of your Giddings wells since 2019 have been in the Chalk. WildFire has been almost exclusively focused in the Eagle Ford Shale. And we noticed your Austin Chalk wells produce a lot more oil than WildFire wells, even though you have a lower oil SKU. So can you -- what subsurface expertise do you believe you have in the Eagle Ford, given you really haven't drilled there? So just trying to understand, you must like something. So just trying to learn a little more about that.

Yes. Honestly, remember, we have a sizable Karnes area asset that is -- it's a mix of Eagle Ford and Chalk, but a lot of Eagle Ford wells there, too. So we do have quite a bit of experience drilling in the Eagle Ford, not necessarily in Giddings, but what I would point out is that while the oil -- cumulative oil may be a little bit less in their Eagle Ford wells versus some of the Chalk that we see, remember that these wells are a substantial amount shallower, probably about 30% shallower than most of the wells we drilled in the Chalk. So the economics are actually very, very good for those Eagle Ford wells despite what you're sort of seeing in the Karnes.

I'd also add, Tim, the chalk doesn't stop in our lease lines. So they have chalk throughout the acreage. They also have Eagle Ford. And we look at the full cycle economics of what money we get back and the returns we make on the wells. And so it's not dissimilar.

Okay. Okay. Makes sense. I appreciate that. And then you have some pretty aggressive deleveraging plans after closing into 2028. Have you hedged any of the oil now? Do you plan to just given kind of how volatile oil prices have been?

Yes, it's a good question. And as hedging has historically not been really a part of our policy, you just sort of talk it through and you ask yourself the question is, why is there a need to hedge and hedging is a form of insurance, as I've always said and you use insurance to protect something. Previously, we've had a very, very low amount of debt. With the WildFire acquisition, we've added a sizable amount of debt here, although our cash flow will also grow. So we believe the additional debt is quite manageable.

Despite that belief, the additional debt does increase the financial risk for the organization from an outsider's perspective. So I think it's critical for us to safeguard our business model, which includes providing a significant return of capital to our shareholders. So we did inherit some hedges on a portion of WildFire's oil production. So those provide us with a -- what I would say is a comfortable floor without giving away too many of the details, a comfortable floor into 2027. And we also expect to opportunistically add some additional hedges with the recent volatility and higher prices that helped us here lately.

So we're doing this to provide additional assurance around our model. And obviously, the current market strength and volatility may also allow us to accelerate that debt reduction. So I think this is useful -- it's a useful tool and tactic right now.

The next question comes from Leo Mariani with KeyBanc.

I was hoping that you could speak a bit more to inventory here. Could you talk about just historical back, you guys have always kind of said that you were focused on 200,000 development acres and felt very confident that there were at least kind of 5 years of drilling there that will very much look like what it is today. Can you speak to something similar on the wildfire assets in terms of how much of that acreage you think is in development area? And is there kind of a rough metric on -- in terms of years of drilling you feel very confident in?

Sure. Yes. Thanks for the question. Look, you're right. I've gone the last 8 years and really not discussed our inventory and while continue to appraise more acreage in Giddings and add inventory. So I don't think our methods or philosophy is going to change much around discussing specific inventory numbers. Look, this is currently one of the largest acreage positions in Texas and South Texas. It's in a well-known, highly prolific oil and gas field. So I'm not worried or concerned about inventory at all. We can maintain our business model with mid-single-digit growth for essentially as long as we would like to.

The short answer on -- to try to get to your question specifically, the answer is a lot. And it's not just a lot. It's a lot, a lot. The better question, is it 3x or 4x a lot. So the expanded answer is just with Magnolia stand-alone, where I've often said, I really don't know how much. I'm very confident that the inventory will continue to grow as we drill, appraise and learn more just as we have over the past 8 years there's been a lot of naysayers, including some of the technical research shops that were very skeptical early on. And it's just recently that we're getting a little bit more credit here with some revised numbers that they put out.

When we founded the company 8 years ago, Steve Chazen was CEO, we really didn't know what we had. We knew that there was a lot of oil and gas in place, but we didn't know if we could improve the predictability and the economics. And so our teams got added and they figured it out. It was about that time that we initiated the dividend payout 5 years ago when we really knew. And I remember someone asked Steve about the inventory, and he said, I have no concerns that my wife will be cashing, getting dividend checks for a very long time. And she's still cashing dividend checks right now and the compound annual growth rate of the dividend is more than 17%.

So I'm confident that my wife is going to be getting dividend checks for a very long time, too. So I'm not really concerned about the inventory at all. This will -- it will continue to grow as we get at it and as we figure it out. It's an extensive, expansive amount of acreage with multidimensional opportunities, as I said, a lot of depth to it, too, in various zones and benches. So I have no concerns.

Okay. Appreciate that. And then I just wanted to touch base on kind of some of the high-level thoughts on a few of the kind of key costs. I mean, I guess this is oilier. You certainly talked about some OpEx improvements over time. Can you give us any kind of high-level color in terms of where like LOE or GP&T or G&A kind of comes out on the WildFire assets at all in comparison to where Magnolia is?

And do you expect any cash tax shield as a result of this? Could this defer some of your taxes for a handful of years?

Yes, sure. So we'll give more specifics after the close on guidance for both production, pro forma production, pro forma capital and some of the specific costs. But to give you a sense, obviously, understand that the WildFire assets are a lot oilier, about 70% oil cut.

So that's going to bring our oil mix pro forma at about 50%. So our LOE will move up a little higher pro forma because of that oilier mix. WildFire's operated LOE was, call it, just under $7.50 a BOE. But pro forma, I expect our LOE to be probably below $6 because we've been running about $5. So to give you a little sense and because of that oily mix, the GP&T will come down a bit. There's less gas. So to give you a sense around that. Cash taxes, I don't expect much there or I expect, to your point, a shield, if you will.

Yes. We'll get a benefit this year from that as well on taxes, cash taxes.

Okay. That's super helpful in terms of that rundown. And then just, Chris, you kind of spoke to funding the cash portion with kind of a mix of some debt and some new equity over time. Can you provide any additional color there? Is that something you hope to prosecute very quickly here? Are you waiting for close? Just any color on that would be helpful.

Well, the over time is not much time. And so the key word is balanced mix of stock and equity. So I would focus on the balance. And it's appropriate that this transaction and acquisition be done in this manner. So it's sort of even without getting into specifics, but it's a good balanced mix of consideration for all parties, the owners and shareholders.

The next question comes from Neil Mehta with Goldman Sachs.

Congrats on the transaction. I mean the assets sit like a glove on the map, Chris. And so I guess the logical question around how far can you extend the laterals as we think about that D&C and facilities synergies, if you could put any quantification around it and how you guys are thinking about prosecuting that.

Yes. I mean there's a lot of adjacent acreage. The adjacency is probably 70% or so. I would tell you, WildFires probably about 8,000, 8,500 foot feet per average on their lateral. We've typically been about that with the extensions, I think we're probably moving in many respects, probably to 10,000 to 15,000 feet. There's going to be a lot of that moving into our program.

That's great. And then one of the parts of this transaction is your oil percentage is going up from 40% to 50%. I mean, Chris, was that a conscious decision from a commodity perspective of where you want to get exposure over time?

And while we're on the topic, can you also talk about decline rates? What does the pro forma portfolio look like relative to what you would be stand-alone?

Yes. So was it a conscious decision? Probably, yes. We've always liked oil and had a bent and a lean and a preference for oil. We have a lot of gas. Don't get me wrong. We have a lot of gas and gas may have its day, but it's not today. And that may be surprised some, but nevertheless, it doesn't honestly surprise us very much.

Oil is a global commodity, and we feel more optimistic about it generally. The economics for us are generally better. So yes, it was a conscious decision. And the decline rate, I would tell you, is probably still low 30s for us on a pro forma basis.

[Operator Instructions] The next question comes from Charles Meade with Johnson Rice.

Chris, Brian and the rest of your Magnolia team there. Just one question for me, Chris, and this -- someone else tried to ask about this. But on hedging and sticking with the idea that it's an insurance policy or derisker, I'm trying to get an idea of what your time line for buying that insurance would be. I mean I think that classically, you don't want to hedge assets for you before you close on them, but you guys are coming in with 0 leverage. And so you have capacity on your own asset base to add some hedges. So I wonder if you could just elaborate on your appetite with respect to the timing?

And also maybe if you could just give us a clue about how much of that wildfire asset base, how much of that is hedged that you're going to be assuming?

Yes. I don't want to get into a lot of the specifics on the numbers yet. But I would tell you the answer to the leaning in on it or the appetite, if you will, is probably sooner rather than later. The economics around the transaction don't require front month oil prices to generate very strong returns. This is sort of gravy, if you will. And so if we can do things in and around where we sit right now, we will probably do that.

As you pointed out, a little bit on our own oil volumes and we anticipate closing. So all good there. And if we have the opportunity to do a little bit more, we may take that opportunistically. And the volatility is providing some of that for us.

So I feel very comfortable that at these prices, this is sort of gravy icing on top, if you will, and it will only accelerate our ability to pay down the debt.

The next question comes from Gabe Daoud with Truist.

Congrats on the deal. I was hoping, Chris, you could maybe just get an update from you on where your current D&C per foot stands in Giddings and maybe how that compared to WildFire. I know you have the $60 million of synergy targets out there. But curious like from where we stand today, what do those numbers look like?

Yes. Our numbers have been hovering below $1,100 per lateral foot, theirs are lower. And so I expect that it will -- it will pull us down. As I mentioned, the shallower depths in the Eagle Ford wells, that will help us there. So I feel pretty good that given the synergies that I mentioned that will be coming down, and that's really part of the lower reinvestment rate that I think their assets bring to the table and helping us on a pro forma basis. So the capital program is going to be quite a bit more efficient and generate more in the way of free cash flow on a combined basis.

Got it. That's helpful, Chris. And then I guess as a follow-up, going back to the resource question. I know you guys generally haven't talked about locations. But maybe on a pro forma basis, how should we think about the number of years that you could sustain the attractive Magnolia business model, which is a lower reinvestment rate, as you noted, and like mid-single-digit production growth. Is it decades? Is it a decade? Just any framing on that would be helpful.

Well, I'm not -- I don't consider myself really old, but it's going to way surpass my career. That's for sure. Is it a decade? Probably and probably beyond that. Look, there's hundreds of locations, hundreds, not just with our acreage, but with WildFire's acreage and opportunity set. So as I said, anything larger at this point that we would consider would really fall by the wayside. There's no need to do that. So this is probably likely the one deal. And as I said, we're very picky and selective around these things. We look at dozens and dozens of opportunities. This is just the one larger deal based on the fit, the overlap, the opportunity set that really would ever make sense for us. Giddings has been a company maker for Magnolia, and this only extends that potential.

The next question comes from Oliver Huang with TPH.

Chris and Brian. Congrats on getting the deal across the finish line. Just a couple of quick ones for me. Are there any sort of drilling commitments to be aware of here just given the expansiveness of the acquired acreage?

None, and nothing significant that I'm aware of or we're aware of at all, nothing on that front.

Okay. Makes sense. And just to kind of follow up on the lateral length extension question from earlier, the 10,000 to 15,000-foot comment, is that specific to the WildFire acreage only? Or is that where the overall program could transition to on a combined basis over time?

That's really specific to the adjacency, as I mentioned. And a significant portion of the acreage, Magnolia's acreage and WildFire's acreage creates this adjacency. So I think I mentioned the numbers being about 70% adjacency. So there's -- there are a lot of chalk wells that will allow us to extend the lateral lengths over time.

This concludes our question-and-answer session and also concludes the conference call today.

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

Good morning, everyone, and thank you for participating in Magnolia Oil & Gas Corporation's First Quarter 2026 Earnings Conference Call. My name is Danielle, and I will be your moderator for today's call. As our call is being recorded. [Operator Instructions] I will now turn the call over to Magnolia's management for the prepared remarks, which will be followed by a brief question-and-answer session.

Thank you, Danielle, and good morning, everyone. Welcome to Magnolia Oil & Gas' First 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 first quarter 2026 earnings press release as well as the conference call slides from the Investors section of the company's website at www.magnoliaoilgas.com. I will now turn the call over to Mr. Chris Stavros.

Thank you, Tom, and good morning, everyone. Thank you for -- all for joining us today for a discussion on our first quarter 2026 financial and operating results.

I plan to briefly speak on our first quarter results, which provided a strong start to the year and consistent performance across our financial and operating metrics. I'll then highlight what turned out to be an active quarter for bolt-on oil and gas property acquisitions for Magnolia, adding to our working interest and royalty interest in both of our operating areas by closing several deals during the quarter. I'll finish up by speaking to Magnolia's 2026 capital and operating plan, which is well positioned during this period of product price volatility, driving incremental free cash flow and improving our financial flexibility. Brian will then review our financial results in greater detail and provide some additional guidance before we take your questions.

Starting with Slide 3 in our quarterly investor presentation, Magnolia delivered another strong and consistent quarter of execution across our financial and operating metrics and centered around our disciplined business model characterized by a low reinvestment rate, high operating margins and moderate production growth. For the first quarter of 2026, total company production volumes grew by 6% year-over-year to 102,600 barrels of oil equivalent per day, with oil production growing by 4% and averaging 40,700 barrels per day. Production in Giddings was the primary growth driver for the company with total Giddings production increasing 9% year-over-year and oil production showing growth of 8% over the same period. Giddings production volumes were a record for the company in the quarter.

Giddings production currently accounts for approximately 82% of Magnolia's total company volumes. The quarter was equally solid around our financial metrics, supported by growth in our oil and gas production and higher oil prices for which production -- or production is entirely unhedged. Our first quarter net income was approximately $101 million or $0.54 per diluted share with adjusted EBITDAX coming in at $253 million. Drilling and completion capital for the period was roughly $129 million, providing a reinvestment rate of 51% of our adjusted EBITDAX. Pretax operating margins averaged 36% for the quarter. Our low reinvestment rate and high operating margins demonstrate our capital spending discipline, proactive cost management and further capture of operational efficiencies.

Magnolia generated approximately $146 million of free cash flow during the first quarter and returned $83 million to our shareholders through a combination of our base dividend on our share repurchase program, where we bought back just over 1% of Magnolia's outstanding shares during the period. Additionally, EnerVest, Magnolia's original private equity shareholder, completed the sale of their remaining ownership position during the quarter. This action simplifies our capital structure through the elimination of any remaining Class B shares outstanding at the end of the first quarter.

As shown on Slide 4, first quarter turned out to be a busy period for acquisitions as we completed the purchase of several small bolt-on oil and gas property acquisitions in both our Karnes area and in Giddings totaling $155 million. These transactions, which closed in the latter part of the first quarter include roughly 6,200 net acres and approximately 500 BOE per day of low-decline TDP, about 45% oil and with significant undeveloped upside opportunities located in highly productive areas where we currently operate and understand well.

In our Karnes area, the acquired acreage creates a sizable and largely contiguous 10,000 gross acre block of primarily undeveloped and highly attractive acreage in the core of the Eagle Ford trend across both Karnes and Gonzalez counties. The acquired tracks increased our working interest in the area to approximately 93% with an average NRI of around 8%. At our current development pace in the Karnes area, this acquisition adds multiple years of development locations and blocks up a large contiguous position in both Karnes and Gonzalez counties, allowing for longer lateral development.

In Giddings, our successful ground game continues to increase our working interest and royalty interest by acquiring new acreage in and around our current operated position. The Giddings transactions increased our interest in approximately 45,000 gross acres in addition to adding some new contiguous acreage, furthering our strategy of buying more of what we already own. Each of these transactions leverage the deep technical knowledge we've gained from our drilling and completion activities in the field while meaningfully extending our already robust inventory of high-return drilling locations, increasing our working interest in existing assets and adding valuable duration to our overall resource portfolio. This further demonstrates our ability to deploy a portion of Magnolia's excess free cash flow into high-quality targeted opportunities.

Our goal in pursuing these is intended to not simply replace produced reserves but to expand our long-term opportunity set and reinforce the sustainability of our strong financial returns. We continue to actively seek out additional asset acquisition opportunities that improve our business using our technical experience in developing the Austin Chalk and Eagle Ford formations in South Texas that provide us with a clear competitive advantage.

As I often mentioned, Magnolia's primary goals is to be the most efficient operator of our best-in-class oil and gas assets to generate the highest return on those assets while spending the least amount of capital on drilling and completing wells. Magnolia's high-quality assets and the strategy of discipline around capital spending should continue to serve us well during periods of product price volatility. Our capital allocation priorities, which include a low reinvestment rate and returning a significant amount of our free cash flow to shareholders remain unchanged. We are maintaining our original activity plan of running 2 rigs and 1 completion crew, which is expected to deliver total production growth of approximately 5% in 2026 and within the same range of drilling and completion capital we outlined earlier this year. Some of this year's activity is expected to occur on the recently acquired acreage.

Oil price differentials have narrowed significantly in recent weeks, which should provide us with higher oil price realizations in the second quarter and similar to the Magellan East Houston benchmark, which is currently higher than the price of WTI. Beyond the benefit of higher oil prices, Magnolia is well positioned for success through the consistent execution of our business model. The absence of commodity hedges on all our production is expected to translate into higher earnings and free cash flow in the current quarter, adding to our significant financial flexibility. I'll now turn the call over to Brian to provide further details on the quarter and some additional guidance.

Thanks, Chris, and good morning, everyone. I'll review some items from our first quarter results and refer to the presentation slides found on our website. I'll also provide some additional guidance for the second quarter of 2026 before turning it over for questions.

Beginning on Slide 6. Magnolia delivered an excellent quarter as we continue to execute on our differentiated business model. During the first quarter, we generated net income of $101 million or $0.54 per diluted share. Our adjusted EBITDAX for the quarter was $253 million with total capital associated with drilling, completions and associated facilities of $129 million, representing 51% of our adjusted EBITDAX. First quarter production volumes grew 6% year-over-year to 102,600 barrels of oil equivalent a day, while generating free cash flow of $146 million.

Looking at the quarterly cash flow waterfall chart on Slide 7. We started the quarter with $267 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 $23 million. During the quarter, we paid dividends of $31 million and allocated $53 million towards share repurchases. We incurred $128 million on drilling completions and associated facilities and leasehold and added $155 million of small bolt-on acquisitions, comprised of additional acreage working interest and royalties. We ended the quarter with $124 million of cash.

Looking at Slide 8, this chart illustrates the progress in reducing our total outstanding shares since we began our repurchase program in the second half of '19. Since that time, we have repurchased 83.7 million shares, leading to a change in weighted average diluted shares outstanding of 28% net of issuances. Magnolia's weighted average diluted share count declined by approximately 2 million shares sequentially, averaging 185.9 million shares during the first quarter. We currently have 11.6 million shares remaining under our repurchase authorization, which are specifically directed toward open market repurchases.

Turning to Slide 9. Our dividend has grown substantially over the past few years, including a 10% increase announced in early 2026 to $0.165 per share on a quarterly basis. Our next quarterly dividend is payable on June 1 and provides an annualized dividend payout rate of $0.66 per share. Our plan for annualized dividend growth is an important part of Magnolia's investment proposition and supported by our overall strategy of achieving moderate annual production growth, reducing our outstanding shares and increasing the dividend payout capacity of the company.

Magnolia continues to have a very strong balance sheet, and we ended the quarter with $124 million of cash. Our $400 million of senior notes does not mature until 2032. Including our first quarter ending cash balance of $124 million and our undrawn $450 million revolving credit facility, our total liquidity is approximately $574 million. Our commenced balance sheet as of March 31 is shown on Slide 10.

Turning to Slide 11 and looking at our per unit cash cost and operating income margins. Total revenue per BOE declined approximately 4% year-over-year due to the decline in NGL and natural gas prices, partially offset by a small increase in oil price. Our total adjusted cash operating costs, including G&A, were $11.57 per BOE in the first quarter of '26 and our operating income margin for the first quarter was $13.84 per BOE or 36% of our total revenue.

Turning to guidance. First quarter D&C capital are expected to be between $120 million and $125 million, and we are reiterating our full year budget we outlined in February of $440 million to $480 million. In addition, we are reiterating our full year 2026 outlook for total production growth of approximately 5%. Total production for the second quarter is estimated to be approximately 105,000 barrels a day. Oil realizations have improved, and we are anticipating prices for the second quarter to be similar to Magellan East Houston benchmark pricing.

Magnolia remains completely unhedged for all its oil and natural gas production and benefiting from the improvements to oil prices. The fully diluted share count for the second quarter of 2026 is expected to be 185 million shares, which is 4% lower than second quarter 2025 levels. We expect our effective tax rate to be approximately 21% and our cash taxes for 2026 to be in the mid-single-digit range. We are now ready to take your questions.

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

Nice quarter. Chris, my first question is just on the very interesting recent bolt-ons that you all have done. Specifically, could you talk about, I don't know, maybe any color how much you're able to -- just on the Karnes side, able to add and wondering by doing this, does this change upcoming activity plans specifically in that play?

I think the important takeaway for me and for us on the Karnes transaction specifically is that we were able to pull this together. It was really sort of a tactical commercial transaction that was a bit unique. We were able to pull this together, creating this 10,000-acre contiguous block of acreage. It's largely undeveloped, very high working interest, advantageous NRI located in a very good area. The undeveloped contiguous nature of the acreage really does provide us with multiple years of drilling.

I can probably count it on my hand in terms of what it adds to us as far as years and beyond. It's sort of a blank canvas, the way I would describe it and allows us to optimally develop the asset. So regarding our plans going forward, it's not going to change our overall allocation around activity or capital or proportional view, but it's going to be easily worked into our drilling program, and I would imagine sooner rather than later.

Perfect. And then just my second question on Giddings development. Specifically, could you speak to -- maybe just talk a bit about what the average pad size and well cost is in that play. And again, what I'm after here is wondering, would you consider now that you're in full development in that play? And if so, how do the economics today compared to a couple of years ago when you were newer in the play and you were certainly doing more testing and kind of drilling what I'd call more one-off wells?

Yes. I mean on the pad size, we've been -- we're pretty close to optimizing that, I would tell you. I mean, occasionally, some of the pads are a little higher, but little -- or a little lower. I mean, on average, there are 3- to 4-well pads, and that's over the full development of that 240,000 acre development area that we talk to or speak of. Like I said, occasionally, there could be a 5-well pad or a 6-well pad or a 3-well pad or a 2-well pad, but on average, about 3 to 4 is sort of optimal.

As far as the economics, they're better than they were earlier because we've gotten more capitally efficient. And we know the play better. We've tightened some things up. We're drilling faster. We're completing faster. We continue to do that. So I think the economics are broadly better.

The next question comes from Phillip Jungwirth from BMO.

Coming back to the Karnes bolt-on, having this large 10,000-acre undeveloped contiguous block, I was just wondering if you could talk about how you see the development scheme here, whether it's wells per DSU, lateral lengths or the zones you can target, just given that there's generally a lot of resource in this area.

Yes. We're getting around the wells per DSU. I mean we're still not quite there yet. But I mean, the laterals will be sort of approaching 10,000 feet in some cases and beyond. So that's substantially more than what we've typically been able to do in the cards area generally.

Okay. Great. And then you noticed -- yes, active quarter for A&D and then you did notice noted in the release that you'll actively be looking to seek out additional acquisition opportunities just to improve the business, leverage technical expertise. Just given that you've grown the company significantly over the years, is there kind of an upper limit on transaction size? And just remind us on balance sheet parameters. if you would consider larger-sized transactions?

I mean it really depends what's out there. We do look at everything, but the plan is not to shock an off. It's not about that. So you're not going to wake up one day, and that's my objective really is to run a public company. So we're trying to build trust and faith within our shareholder base in terms of what we're doing. So you won't find us looking at out-of-basin deals. All of what we look at is really what we understand and within our ability to manage and in and around our neighborhood. So we should know it well. So the size really sort of depends on what's out there and as things become available. As you'd imagine, with pricing doing what it's done, there's probably more things that are available or out there, but it just sort of really depends what it looks like and how it fits into our possibility or the art of the possible, if you will.

The next question comes from Peyton Dorne from UBS.

You're obviously keeping the budget a little unchanged here, and I know the preference isn't to add any rigs or crews kind of writ large. But I'm just curious on the opportunity to maybe accelerate some workovers or some timing of the tails across the asset base just to kind of take advantage of the higher oil prices that we've seen year-to-date.

Yes. No, we could certainly consider some of those things, whether it's a little bit more appraisal or maybe even an exploration well. The math or arithmetic on drilling faster or adding more activity, current oil price is certainly not lost on me, I get it. But look, I've been doing this for a long time. I view this more as a marathon, not a sprint. So you never know what's right around the bend. With every barrel we accelerate pull forward, it simply means I have to replace that barrel that much quicker and it creates a little bit of added attention in terms of the higher rate of decline that we face. We're planning to grow about 5% this year, which is probably a little higher than most. We have a reasonable chance of surprising a little higher because of good well performance. I'll probably take the over on that one.

If we were to add anything new, I think almost as you said, it would probably be a little bit more on the appraisal work side. Yes, maybe workovers, but sort of less incremental or maybe even an exploration well. But again, I wouldn't -- it's not a dramatic shift or change because of the price per se. However, at current oil prices, it also wouldn't surprise me to see a little bit more non-op activity as well.

Okay. Great. We'll look for all those. And then just on the recent acquisition and some of the past transactions, you guys kind of highlighted the pickup of some royalty interest across the leasehold. I wonder if you could just kind of quantify the total royalty acreage that you have right now? And kind of do you see acquisitions of royalties or mineral interest kind of becoming a larger part of the acquisition strategy on maybe a go-forward basis?

Yes. I mean I'll let Brian answer on that as well. But honestly, if you're speaking to something where acquiring royalties is really more sort of an event that leads to something to either monetize it in a financial opportunity, the answer is not really. This is just enhancing our own economics.

Yes. I mean if you -- we do have relatively high NRI, especially at Giddings. It's definitely, we'll call it, 50-plus thousand a day in terms of production that's straight from royalties, but that really enhances our margin. And the ultimate goal is to control as much as you can and have the highest margins you can. And whether it's royalties or higher working interest, we want to own more of what we have.

The next question comes from Carlos Escalante from Wolfe Research.

I wanted to circle back on the deal. I know that got a lot of questions this morning, but just curious to hear your perspective on how you thought this deal cleared at this prices because you typically don't see M&A at peak oil prices if you believe this is the peak or we're close to some kind of peak. So if acreage of this quality is clearing at this prices, what does that say about the broader bid-ask in Karnes and also Giddings? And how deep is the pipeline of similar opportunities relative to when we last talked to you last quarter, considering the move in commodity pricing?

Carlos, thanks for the question. I never said that it cleared at current prices. So we were in conversations around this for a period of time and sometimes better to be fortunate than good. So what I would tell you about the bid-ask, as you can imagine, like I said earlier, it's clearly easier if you're a seller to sort of come to market now with the hope or belief that you'll find willing acquirers of assets. So there's lots of things out there. And you ask anyone, there's plentiful. It's really a -- I won't say a seller's market so much. Maybe that's not the best way to put it. But just in terms of availability or opportunities that are coming, whether they're in processes or one-off opportunities, there's a lot to be had if you want it.

The way I think about it is it's got to make sense. When we look at anything for Magnolia, this needs to support our business model and have characteristics that look similar to what we already are. And frankly, improve us that I always joke a little bit. I mean the objective of any acquisition is to make it better, not worse. And so there can be these unique one-off opportunities irrespective of the price that it may clear at that still work for some depending.

Yes. And my question was precisely to get at the motivation behind the deal, but it sounds like you had been working on it. And I think that's much of the work for the answer. On my follow-up, my question really is on your realizations as a whole. I know I've pushed you guys around asking you this question for quite some time now. But I'm looking for some sort of validation that the second half of this year when we bring so much Permian gas to market that may be connected to part of the cell points you guys sell your gas in won't be affected. And you've had some very thoughtful commentary around that before. But as we get close to those pipelines coming to market, I wonder if you have any new perspectives on what the dynamics will be on the natural gas front.

The new perspective is really gained through the experience of the old perspective or the old outcome, which oftentimes, we'll get these exact questions on infrastructure that comes on that could create changes in realizations or free up supply in some fashion. Specific to what you're talking about, as an example, last year, when Matterhorn came on, that was the question and there was a concern that, that would have an impact, yet it did not. And you're seeing what's going on in Waha most recently, and it's -- here we are. So I don't know the true answer, but my experience suggests that it may not be all that different than what occurred a year ago, irrespective of what's happening right now.

Carlos, I'd also add, I mean, both oil and gas. We sell our products at the market on the water. We're very close to where our products are sold. The tolling fees are less, and they're attractive pricing. And so you're seeing that in the oil market today. You're seeing that at Ship Channel. And so we're happy with the markets that we sell.

[Operator Instructions] The next question comes from Neil Mehta from Goldman Sachs.

First question is just around capital returns or shareholder returns, specifically the repurchase. You guys knocked out another 2 million shares in the first quarter. And so just your perspective on the buyback here and how it fits into the tools you have to create shareholder value.

Yes. It's always been part of the model as far -- frankly, its compounding effects are enormously beneficial in terms of helping us with the dividend growth and growth per share in the dividend, if you will, by sort of reducing the actual cash outlays while you grow the dividend on a higher per share rate. Look, it's part of the same ABCs of what we do on our model. And frankly, I see it as part of a consistent plan for us. I don't see that going away. I think it's at a size that is appropriate for what we are and what we're capable of doing and delivering consistently. So our shareholders like it. It rewards the remaining holders of which I'm one, and I enjoy it too. And so I think it's a good way to create shareholder value over time.

Got it. And that's the follow-up is just the dividend. I think you guys talked about at least 1% of the stock getting bought back every quarter over the long term, but then you also talk about a 10% long-term dividend growth rate. How do you feel about that double-digit level? And is there potential for upside if we end up in a higher for longer environment and given the strength of the balance sheet?

Yes, I try to catch myself on really creating these targets, the target is somewhat artificial in a way, but it's really designed to speak to what the business is capable of doing. So if the business grows mid-single digits, which I would define as 4%, 5%, 6% and then you're buying back 1% of your shares per quarter, the -- it's built into sort of the investment proposition of what we're doing. So the dividend growth is an outcome of what I just said around the volume growth and the share repurchases. So it sort of just falls out of the model.

This concludes our question-and-answer session, and the conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

Good morning, everyone, and thank you for participating in Magnolia Oil & Gas Corporation's Fourth Quarter 2025 Earnings Conference Call. My name is Cloe and I will be your moderator for today's call. [Operator Instructions] Our call is being recorded.

I will now turn the call over to Magnolia's management for their prepared remarks, which will be followed by a brief question-and-answer session.

Thank you, Cloe, and good morning, everyone. Welcome to Magnolia Oil & Gas' Fourth Quarter Earnings Conference Call. Participating on the call today are Chris Stavros, Magnolia's Chairman, President and Chief Executive Officer; and Brian Corales, Senior Vice President and Chief Financial Officer. .

As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on risk factors that could cause results to differ is available in the company's annual report on Form 10-K filed with the SEC. A full safe harbor can be found on Slide 2 of the conference call slide presentation with the supplemental data on our website. You can download Magnolia's fourth quarter 2025 earnings press release as well as the conference call slides from the Investors section of the company's website at www.magnoliaoilgas.com.

I will now turn the call over to Mr. Chris Stavros.

Thank you, Tom, and good morning, everyone. We appreciate you joining us today for a discussion of our fourth quarter and full year 2025 financial and operating results. I plan to briefly speak to last year's results, which closed out another year of strong, consistent performance and execution showing the beneficial characteristics and merits of our differentiated business model and during a year of elevated product price volatility. Our model has allowed us to deliver strong free cash flow and cash returns to our shareholders resulting from superior asset performance and our continued focus on capital discipline, cost containment and visible efficiency improvements. I'll conclude by providing an outlook of Magnolia's 2026 capital and operating plan which is expected to deliver moderate growth with a similar level of capital spending that provides us with further opportunities to capture low-cost resource across our acreage position. Brian will then review our financial results in greater detail and provide some additional guidance before we take your questions. .

Beginning on Slide 3 of our quarterly investor presentation and looking at the highlights, Magnolia delivered another solid quarter and year of performance marked by steady execution of our capital-efficient business model and our high-quality assets. I'm particularly proud of our ongoing dedication and focus shown by both our operating teams in the field and our Houston staff. Their continued hard work and diligence is a significant factor behind Magnolia's success. Our business performed exceptionally well throughout the year, driven by stronger-than-expected well results, improved efficiencies, lower unit costs and our committed -- commitment to capital discipline, as I mentioned.

For the full year 2025, total company production grew by 11% to approximately 100,000 barrels of oil equivalent per day with oil production growing by 4% and averaging nearly 40,000 barrels per day. Operationally, we continue to make strides in reducing our field level cash operating expenses, which declined by 7% to $5.12 per BOE during 2025. The better-than-expected well productivity we experienced during the first half of last year not only provided us with higher production growth in 2025, but also allowed us to save capital by deferring some well completions into this year. Our teams are also able to drive a more efficient drilling and completions program last year in Giddings with our average drilled feet per day increasing by 8% and with completed feet per day improving by 6%.

Turning specifically to the fourth quarter, we achieved a new company record for our production, averaging nearly 104,000 barrels of oil equivalent per day and [ 40.7,000 ] barrels of oil per day. These both marked a sequential increase of 3% and reflected the continued strong performance from our wells. Financially, the quarter and year were equally strong and aligned with our goal of generating consistent and sustainable free cash flow through disciplined capital allocation. Our fourth quarter adjusted net income was approximately $71 million or $0.38 per diluted share with adjusted EBITDAX coming in at $216 million.

Our drilling and completion capital for the period was roughly $117 million, representing 54% of our adjusted EBITDAX. Pretax operating margins averaged 33% for the year despite a more than 15% annual decline in our oil price realizations. Our low reinvestment rate enabled us to generate free cash flow of more than $425 million for the full year. We stood by our commitment to return a significant portion of that free cash flow to our shareholders, distributing approximately 75% through a combination of our base dividend and share repurchases. In total, we repurchased approximately 8.9 million shares throughout the course of 2025, reducing our diluted share count by roughly 4.5%. This not only accretes value on a per share basis, but also reinforces our business model that leads to a serial compounding of value. Our balance sheet ended the year in a position of strength, allowing us to navigate product price uncertainty and provides us with ample liquidity and a cash balance giving us flexibility to selectively pursue opportunistic bolt-on additions to our portfolio.

As shown on Slide 4, our strategy is designed to produce steady mid-single-digit total production growth, high pretax margins and reliable free cash flow while maintaining a low reinvestment rate and a strong balance sheet. The strength of this model and the strategy is clear when looking at Magnolia's longer-term performance across these key financial metrics.

Looking at Slide 5. Magnolia has maintained one of the lowest capital reinvestment rates among the U.S. oil and gas producers over the past 5 years, while delivering one of the highest rates of production growth per share.

As shown on Slide 6, Magnolia continues to achieve strong pretax operating margins, driven primarily by our low-cost, high-quality asset base, which is also in close proximity to large consuming markets on the U.S. Gulf Coast.

Slide 7 highlights the continued strength of our balance sheet, which remains best-in-class in the industry. Maintaining low leverage is a critical part of our strategy as it reduces financial risk while preserving substantial flexibility and strategic optionality. While many oil and gas operators often excel in 1 or 2 of these areas, we believe that our combination of our low capital reinvestment rate above average per share growth, high operating margins and minimal debt is unique, especially for a small to midsize operator. This powerful recipe allows us to generate high corporate returns, maximize our free cash flow generation and sustain our strong and consistent capital return program for shareholders.

Slide 8 illustrates our corporate level returns showing 2025 is another strong year with return on capital employed, ROCE of 18% and well above our cost of capital despite year-over-year lower oil prices. Over the last 5 years, Magnolia has generated an average ROCE of 34% and more than 3x our weighted average cost of capital. These exceptional returns stem from our prudent capital allocation, consistent low debt levels, ongoing share repurchase program and perhaps most importantly, our low-cost, high-quality assets. Case in point, Magnolia added approximately 50 million BOE of proved developed reserves during the year. On accounting for all expenditures to add these reserves, this resulted in organic proved developed finding and development costs or F&D of $9.25 per BOE. During the 3-year period from 2023 to 2025, Magnolia's organic proved developed F&D cost averaged $9.85 per BOE. This demonstrates our high quality and low cost of supply asset base.

Looking ahead into 2026, we're committed to the principles that have guided us from the start and have proven to be successful thus far. We plan to remain fiscally prudent and disciplined with our capital spending expected to be approximately flat year-over-year while delivering total production growth of approximately 5%. As I've often said, Magnolia's primary goals and objectives are to be the most prudent and efficient to be the most efficient of our -- and our best-in-class oil and gas assets to generate the highest return on those assets, while spending the least amount of capital on drilling and completing wells no matter what the product price.

Last year was another example of our successful delivery on these goals. We achieved double-digit production growth with less capital than originally planned, repurchased more than 4% of our outstanding shares recently announced a 10% increase in our dividend, our fifth consecutive annual increase and completed approximately $67 million of bolt-on acquisitions, furthering our resource opportunity set.

To summarize, Magnolia is well positioned and consistently guided by the principles of our business model. Our high-quality assets and strategy of continued capital spending discipline, proactive cost management and pursuit of further operational efficiencies should serve us well during periods of product price volatility. Our consistent policy of low leverage and the lack of commodity hedges essential to our strategy, providing what as with downside protection while allowing for upside to product prices and the ability to generate value through commodity cycles.

I'll now turn the call over to Brian for a review of our financials and provide some additional guidance.

Thanks, Chris, and good morning, everyone. I will review some items from our fourth quarter and full year results and refer to the presentation slides found on our website. I'll also provide some additional guidance for the quarter -- for the first quarter of 2026 and in the remainder of the year before turning it over for questions.

Magnolia ended 2025 with a strong performance across our operations. Starting on Slide 10. During the fourth quarter, we generated total adjusted net income of $71 million or $0.38 per diluted share. Our adjusted EBITDAX for the quarter was $216 million with total capital associated with drilling completions and associated facilities of $117 million, representing 54% of our adjusted EBITDAX. For the full year, adjusted EBITDAX was $906 million with D&C capital representing 51% of EBITDAX. Fourth quarter production volumes grew 11% year-over-year to 103.8 barrels of oil equivalent per day. For the full year, production volumes grew 11% to 99.8 barrels of oil equivalent per day with oil growth of 4%. During the year, we repurchased a total of 8.9 million shares and our diluted share count fell by 4% year-over-year.

Looking at the quarterly cash flow waterfall chart on Slide 11. We started the year with $260 million of cash. Cash flow from operations before changes in working capital was $906 million with working capital changes and other small items impacting cash by $41 million. Throughout the year, we added $67 million of bolt-on acquisitions. We paid dividends of $117 million and allocated $205 million towards share repurchases. We incurred $469 million on drilling completions and associated facilities and leasehold and ended the year with $267 million of cash.

Looking at Slide 12. This chart illustrates the progress in reducing our total outstanding shares since we began our repurchase program in the second half of 2019. Since that time, we have repurchased 81.8 million shares leading to a change in weighted average diluted shares outstanding of approximately 27% net of issuances. Magnolia's weighted average diluted share count declined by more than 2 million shares sequentially, averaging 188 million shares during the fourth quarter. As Chris discussed, the Board recently approved a 10 million share increase to our share repurchase authorization leaving 12.9 million shares remaining under our current repurchase authorization, which are specifically directed towards repurchasing Class A shares in the open market.

Turning to Slide 13. Our dividend has grown substantially over the past few years, including a 10% increase we recently announced to $0.165 per share on a quarterly basis. Our next quarterly dividend is payable on March 2 and provides an annualized dividend payout rate of $0.66 per share. Our plan for annualized dividend growth is an important part of Magnolia's investment proposition and supported by our overall strategy of achieving moderate annual production growth, reducing our outstanding shares and increasing the dividend payout capacity of the company. Magnolia continues to have a very strong balance sheet, and we ended the quarter with $267 million of cash. Our $400 million of senior note does not mature until 2032. Including our fourth quarter ending cash balance of $267 million and our undrawn $450 million revolving credit facility, our total liquidity is approximately $717 million. Our condensed balance sheet as of December 31 is shown on Slide 14.

Turning to Slide 15 and looking at our per unit cash costs and operating income margins. Total revenue per BOE declined 13% quarter-over-quarter due to the decline in oil prices. Our total adjusted cash operating costs, including G&A, were $10.64 per BOE in the fourth quarter of 2025. Our operating income margin for the fourth quarter was $9.85 per BOE or 30% of our total revenue. The decrease in our quarter-over-quarter pretax operating margin was entirely driven by the decrease in commodity prices and were further benefited from lower DD&A expense.

On Slide 16, Magnolia continues to have a very successful organic drilling program. The total proved developed reserves at year-end 2025 were 167 million barrels of oil equivalent. Excluding acquisitions and price-related revisions, the company added 50 million barrels of oil equivalent of proved developed reserves during the year. Total drilling and completions capital was $461 million in 2025, resulting in organic proved developed F&D cost of $9.25 per BOE and reflective of our current drilling program. The 3-year average organic proved developed F&D cost was $9.85 per BOE.

Turning to guidance. We expect our 2026 drilling completions and facility capital to be in the range of $440 million to $480 million, which includes an estimate of nonoperated capital that is similar to that of 2025. At the midpoint, this is similar to prior year's capital cost despite planning more wells in 2026. We expect first quarter D&C capital expenditures to be approximately $125 million and anticipate this to be the highest quarterly 1,500 barrels of oil equivalent per day of winter weather impacts experienced in January.

Total full year 2026 production growth is expected to be approximately 5%. Oil price differentials are anticipated to be approximately $3 per barrel discount to Magellan East Houston and Magnolia remains completely unhedged for all of its oil and natural gas production. The fully diluted share count for the first quarter of 2026 is expected to be approximately 187 million shares, which is 4% lower than first quarter 2025 levels. We expect our effective tax rate to be approximately 21%, with all of this being deferred.

We are now ready to take your questions.

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

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

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

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

Yes. Brian put some numbers around the bolt-on transactions, acquisitions, some of the ground game that has led to some of the bolt-ons that we've done over the last couple of years. And what I'd say is that it's not predictable. But we've done a good job, I think, with that ground game in Giddings, western Eagle Ford, Karnes area, I really do expect it to continue. Like I said, it's just tough to predict in terms of the timing.

The competition, I would tell you it has risen over the last year, the larger the opportunity or maybe deal size or item that you might be looking for the tougher it is and maybe the more expensive it is. But we've done a good job of better understanding the things that we're looking for in terms of the subsurface and in and around where we currently operate. I'm not and never really have been a big proponent of very large PDP heavy deals as you're more likely to pay full value for these or even higher. I think part of that is within your question in terms of what you might be seeing in the Permian and the Delaware.

I really much prefer to focus on opportunities where we have more undeveloped upside but you're generally right, the prices for acreage has climbed. I mean, we're not out there looking to build a data center anytime soon. In terms of what you're seeing for what's happening in real estate or land prices. But for all I know, we could be competing with those -- with some of those who are looking to build a data center. I just don't know but it's certainly reflected in some of the elevated levels of pricing.

The next question comes from Phillip Jungwirth with BMO.

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

Yes, sure. We had been -- if I go back a year plus, we were looking at a standard cost of -- or the cost of the standard Giddings well as sort of maybe $1,100 a foot. And it was trending through that period up to now, maybe down towards $1,000 a foot. So I think that's sort of what we're looking at right now for a standard Giddings well, which is between 8,000 to 8,500 feet. So something between that probably gives you a reasonable estimate and maybe closer to $1,000 a foot, if that helps you.

On the service cost, things are flat to slightly down into this year, but we'll see where this goes as far as commodity prices. We have regular conversations with our service partners, and we want to keep them working because they've been good partners. Most recently, this has been a tough way to make a living. I think the OFS market continue to experience some pricing pressure going through this year. And certainly, the prices for oil are 60 or below. We've locked in some of our service costs with our key providers through most of the first half of this year, and we'll be going back probably later in the spring to start looking at negotiating for things in the back half of the year and sort of close it out. But I feel as if we're in a good position and we're not looking to take advantage, but it's like I said, it's tough. And I get it but we're also in the business to make a margin as well. So things are favorable for us, less favorable for the [ OFS ] guys.

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

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

The next question comes from Peyton Dorne with UBS.

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

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

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

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

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

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

Yes. These are what I alluded to or mentioned before, probably -- not probably, they are more on the PDP heavy side, have been well developed, has sort of been through the machination of time and heavily drilled up. So you really -- you don't want to buy somebody else's decline curve. He never want to get involved with that if you can avoid it. So I'm looking for things that have untested upside or just upside undrilled acreage. And those are tougher things to be had. I'm just not looking to -- you're going to pay full value or better on this PDP heavy stuff. And so I think generally, that's what those larger things would look like. We probably also like to lean a little bit more on the liquids side on the oil side, if we can do it or find it.

So not averse to gas necessarily, but if we can -- there's going to be some production that comes along with it, I'd probably prefer to have a little bit more on the oil side. The other thing, too, large deals come with obviously greater risk. And so you just want to be sure that you can manage this and if you have a good understanding of it. So whatever we're going to do or whatever going to look like, has to sort of start off with the understanding that we have a good firm view of what we're getting ourselves into subsurface-wise and whether or not we can continue to manage it going forward. So lots of looking at old things that are being hived off by publics. It's interesting, but you just got to make sure you understand it well, and it's actually contributing to the business in a positive way fits into our model and can be accretive to the equity.

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

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

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

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

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

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

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

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

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

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

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

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

The next question comes from Carlos Escalante with Wolfe.

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

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

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

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

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

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

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

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

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

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

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

The next question comes from Charles Meade with Johnson Rice.

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

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

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

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

I'm sorry, but what your question is getting at, what exactly?

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

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

The next question comes from Tim Moore with Clear Street.

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

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

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

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

The next question comes from Zach Parham with JPMorgan.

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

There's -- we pretty much take a backward look on this and look at our drilling plan. The drilling plan, I would tell you and the anticipated outcome is not very different in terms of the sets of wells that we're expecting planning to drill as far as what this year's program. So there's a reasonable chance that things could turn out better than what we're predicting. Certainly, it turned out that way last year. But you can't -- there's no guarantee I mean so -- but there is a reasonable chance that some of that will occur in certain areas.

So it's a balanced program. It's designed to sort of deliver moderate expectations for volume growth and factoring in some sorts of levels of risk. But I think as I look at the risk this year, frankly, it doesn't even feel as great as it was last year and last year turned out okay. So I think the outcome will be pretty good.

The next question comes from Paul Diamond with Citi.

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

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

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

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.

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.

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.

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.

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

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?

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.

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.

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.

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

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.

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.

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?

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.

The next question comes from Carlos Escalante from Wolfe Research.

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.

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.

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?

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.

The next question comes from Charles Meade from Johnson Rice.

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?

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

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.

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.

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?

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.

The next question comes from Peyton Dorne from UBS.

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.

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.

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

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?

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%.

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?

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.

The next question comes from Zach Parham from JPMorgan.

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?

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.

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.

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.

The next question comes from Tim Moore from Clear Street.

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?

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.

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?

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.

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

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?

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.

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?

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.

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

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?

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.

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?

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.

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.

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?

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

The next question comes from Greta Drefke from Goldman Sachs.

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?

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.

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?

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.

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