Magnolia Oil & Gas Corporation Class A

Good morning, everyone, and thank you for participating in Magnolia Oil and Gas Corporation's first quarter 2025 earnings conference call. My name is Megan, and I will be your operator for today's call. At this time, all participants will be placed in a listen-only mode as 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, Megan, and good morning, everyone. Welcome to Magnolia Oil and Gas's first quarter earnings conference call. Participating on the call today are Chris Stavros, Magnolia's president and chief executive officer, and Brian Corrales, 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 supplemental data on our website. You can download Magnolia's first quarter 2025 earnings press release, as well as the conference call slides, from the investor section of the company's website at .magnolioilgas.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 first quarter 2025 financial and operating results. I plan to speak to our first quarter results, which puts Magnolia on a very solid foundation to start the year and in a strong position with extensive flexibility to maneuver through the current product price volatility and macroeconomic uncertainty. I will briefly discuss how our asset quality, notably in gettings, continues to drive our operational execution and providing us with further confidence in our plan for this year. I'll conclude by giving a brief update of Magnolia's 2025 capital and operating plan, where we now expect to see higher production growth with lower capital spending, resulting in a more capital-efficient program and in accordance with our business model discipline. Brian will then review our first quarter financial results in greater detail and provide some additional guidance before we take your questions. Focusing on slide 3 of the investor presentation, Magnolia delivered strong operational and financial results during this year's first quarter. We achieved a record quarterly production rate of 96.5 thousand barrels of oil equivalent per day during the quarter, which was well ahead of our earlier guidance. We made a tactical decision to bring a couple of multi-well pads online in the first quarter that are in a gassier portion of gettings and to take advantage of higher natural gas prices historically seen during the winter months. The wells not only exceeded our performance expectations but are also exhibiting a shallower decline profile. The outperformance from these wells helped drive the first quarter -over-year total production growth to 14 percent, in addition to oil production growth of 4 percent. Total production at gettings grew by 25 percent compared to the prior year quarter, with gettings oil volumes growing by 17 percent. Our first quarter financial results were also strong, with total adjusted net income for $106 million and adjusted EBITDAX of $248 million, both up 9 percent compared to the year ago period. Operating income margins were 39 percent in the quarter and our annualized return on capital employed was 23 percent. Our DNC capital spending was $130 million, with a reinvestment rate of 53 percent during the first quarter. The first quarter rate of capital outlays is expected to be the highest quarterly spending rate for the year. Magnolia generated free cash flow of $111 million and we returned 74 percent of the free cash, or approximately $82 million, to our shareholders through our growing-based dividend and ongoing share repurchase program. Much of the outperformance seen from the wells I mentioned earlier originated from a newer area of gettings, which we had previously appraised, ultimately leading to the acquisition of additional acreage and the completion of our first multi-well pads late last year and into early 2025. In addition to the strong performance and lower than expected declines, these wells also generate strong financial returns with quick payback periods. Other areas within gettings also saw strong oil production performance with meaningful associated gas volumes. The outperformance we experienced this past quarter in gettings is not a new phenomenon for us.

Rather,

we have more commonly and consistently seen the results in gettings positively surprise us in terms of well performance and productivity as we have deployed more modern completions design and technology to this older vintage field. Our subsurface team has done an outstanding job of advancing our knowledge of the Austin Chalk Reservoir. Our drilling and completion crews continue to execute on time and below budget, and our production group ensures that the wells are producing in the most efficient manner. These factors have been critical to the successful execution of our business model by maximizing our high return growth for our gettings asset and with the Carns area providing significant free cash flow. As a result of the stronger than expected well performance and which has continued into the second quarter, we are increasing our full year 2025 production growth guidance range to 7 to 9% from a range of 5 to 7% previously. At the same time, we are lowering the range for 2025 capital spending to $430 to $470 million, a reduction of approximately $25 million or more than 5% from the midpoint of our original spending plan. Capital discipline continues to be one of the core principles of Magnolia's business Within the backdrop of current macroeconomic uncertainty and weaker product prices, we see no reason to be overly heroic in terms of pursuing and generating even higher production growth through our original capital spending and activity levels. The higher growth rate and improved operational flexibility that we now expect to achieve in 2025 is primarily a function of the outperformance of the wells and operational efficiencies we have captured through the first part of this year. The reduction to our capital and activity plan will lead to deferring the completion of several wells into next year. To summarize, at current product prices, we now expect to see somewhat higher production in 2025 compared to our previous forecast and with less capital spending, while maintaining a high level of flexibility within our activity program for the remainder of the year. Magnolia's operations remain consistent and steady and we continue to execute a differentiated, focused and investable EMP business model that is enduring. Our objective, as always, is to be the most efficient operator of -in-class oil and gas assets, generating the highest returns on those assets while employing the least amount of capital for drilling and completing wells. As we noted earlier this year, our teams took proactive measures during the last couple of years to reduce both our field-level operating costs as well as working with our key oil service providers and material vendors to lower our overall well costs. These early efforts, taken during a period of higher product prices, has reduced our overall cost structure, placing us in a continued strong position should product prices continue to weaken. Our low level of debt, business model oriented toward capital discipline and our high quality assets are valuable characteristics, particularly during periods of greater uncertainty, and allow Magnolia to operate from a position of strength and manage through periods of weaker product prices or potential market instability. Despite the lower commodity price environment, we will continue to limit our reinvestment rate to 55% of our gross cash flow or EBITDAX, allowing for a significant return of free cash to shareholders through our base dividend and ongoing share repurchases. Any additional free cash accrues to the balance sheet, allowing us to opportunistically pursue creative, bolt-on oil and gas property acquisitions that can improve our opportunity set and enhance the durability of our business model. As I've emphasized, Magnolia's consistently strong execution sports the competitive advantage we have in South Texas, Eagleford, and Austin Chalk, and we will continue to focus our attention and capital in these areas to further generate and compound value for our shareholders. I'll now turn the call over to Brian to provide some further details on our first quarter 2025 results and additional guidance for the second quarter.

Thanks, Chris, and good morning, everyone. I will 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 2025 and the remainder of the year before turning it over for questions. Beginning on slide 5, Magnolia had a strong start to 2025 as we continued to adhere to the business model through these uncertain times. During the first quarter, we generated total net income of $107 million, with total adjusted net income of $106 million, or $0.54 per diluted share. Our adjusted EBITDAX for the quarter was $248 million, with total capital associated with drilling completions and associated facilities of $130 million, representing approximately 53% of our adjusted EBITDAX. First quarter capital was expected to be the highest quarterly outlay for the year. First quarter production volumes grew 14% year over year to 96.5 thousand barrels of oil equivalent per day, while generating free cash flow of $111 million. Looking at the quarterly cash flow waterfall chart on slide 6, we started the year with $260 million of cash. Cash flow from operations before changes in working capital was $232 million, with working capital changes and other small items impacting cash by $7 million. During the quarter we paid dividends of $30 million and allocated $52 million towards share repurchases. We added $24 million of small bolt-on acquisitions during the quarter, comprised of working interests, royalties, and some additional surface acreage, and this did not come with any production. We incurred $131 million on drilling completions, associated facilities, and leasehold, and ended the quarter with $248 million of cash. 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 75 million shares, leading to a change in weighted average diluted shares outstanding of 24% net of issuances. Magnolia's weighted average diluted share count declined by approximately 2 million shares sequentially, averaging 194.2 million shares during the first quarter. We currently have 9.6 million shares remaining under our repurchase authorization, which are specifically directed toward 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 June 2nd 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 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 248 million of cash. Our $400 million of senior notes do not mature until 2032. Including our first quarter ending cash balance of $248 million and our undrawn $450 million revolving credit facility, our total liquidity is approximately $700 million. Our condensed balance sheet as of March 31st is shown on slide 9. Turning to slide 10 and looking at our per unit cash costs and operating income margins. Total revenue per BOE declined approximately 3% year over year due to the decline in oil prices and partially offset by an increase in natural gas and NGO prices. Total adjusted cash operating costs, including G&A, were $11.74 per BOE in the first quarter of 2025. Operating income margin for the first quarter was $15.63 per BOE or 39% of our total revenue and in line with first quarter 2024 levels. Our year over year revenue per BOE declined $1.09 due to decline in oil prices. Yet our operating income margin only declined by $0.52 per BOE. This highlights our success reducing our lease operating expenses last year enabling us to preserve our margin percentage in a lower price environment. First quarter per BOE is expected to be the highest level of the year. Turning to guidance. We have lowered our 2025 drilling completion and facilities capital spending to be in the range of $430 to $470 million from a prior range of $460 to $490 million. A decrease of slightly more than 5% at the midpoint. This includes an estimate of non-operated capital that is about the same as 2024 levels. Importantly, due to the well outperformance that Chris described, we are increasing our full year production guidance to 7 to 9% from a prior range of 5 to 7%. Total production for the second quarter is expected to be similar to the first quarter The second quarter is expected to be approximately $1.5 million per BOE. The second quarter is expected to be approximately $1.5 million per BOE. The second quarter is expected to be approximately $1.5 million per BOE. Oil price differentials are anticipated to be approximately a $3 per barrel discount to Magellan East Houston and Magnolia remains completely unhedged for all its oil and natural gas production. The fully diluted share count for the second quarter of 2025 is expected to be approximately $193 million shares, which is 4% lower than second quarter 2024 levels. We expect our effective tax rate to be approximately 21% and our cash tax is expected to be between 7 to 9% for the full year 2025. We are now ready to take your questions.

We will now begin the question and answer session. To ask a question, you may press star then 1 on your telephone keypad. If you are using a speaker phone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star then 2. At this time, we will pause momentarily to assemble our roster. Our first question comes from Carlos Escalante with Wolf Research. Please go ahead.

Hey, good morning, team. Good morning, Chris and Brian. First of all, congratulations on the milestone for the year. It's certainly great to see and very encouraging. My first question is to perhaps explore a little bit about what's going on with these new wells and what this means for Magnolia. So it seems to us that the incremental wells on the area have some existing prior activity by industry that hasn't been specifically touched by you or minimally where you've been minimally active. How should we interpret the general area in terms of inclusion to your definition of development acres versus undeveloped acres? And subsequent to that is, is this an area you would prioritize developing versus your more usual gatings development in a way weighted with a bias perhaps to the general area? A little more of liquids?

Thanks, Carlos, for the questions. So to answer some of the questions, I sort of have to assume that what you're guessing on in terms of the area is correct. And based on the characteristics that you mentioned, you would not be correct. So I'll answer it the way we can answer it. I'm not going to tell you, unfortunately, for you. I'm not going to tell you exactly for competitive reasons exactly where this is. We're just not going to disclose that. But what I will say is that this is a new area, as we talked about. It is in what I would call now our development area. Part of it may have been already sort of noted in our couple of hundred thousand acres of development area, and part of it is not. So if you wanted to count acres, I suppose you could say that there's more development acres to be added. And not just by the way, not just from this area, but probably from other areas as well, because the 200,000 acre number is fairly stale. In terms of what the wells did and how they looked, they've been producing for a bit of time. We have a meaningful amount of measurement period, if you will, where I could tell you we directed some of this activity because it was, in our view, a gaseous area and we wanted to take advantage of that. Unfortunately, our gas realizations were double what they were a year ago, so that worked out just fine. But importantly, and I think maybe critically, the financial returns and payback periods on these wells were very strong because the average well probably produced maybe 500 barrels a day of oil in addition to the gas. And so that's worked out that much better. And call these wells roughly in this area that I'm speaking to that we called out roughly in terms of the outperformance, about a dozen wells. I wouldn't tell you that, characteristically, there's some things on the subsurface level that are different from other areas of Giddings, but that's not a new statement that I would make. I mean, Giddings is not necessarily homogenous. There are different areas of Giddings throughout the field. This particular area has its own characteristics. I'm not going to get into too much of it, but nevertheless, the performance was very good, both oil and gas, beyond our expectations. I mentioned the shallower rates of decline. And frankly, just based on, I mentioned the returns a little bit, but you're looking at F&D costs for these wells that are in the high single digits on a per barrel basis. So, that's sort of what I would say. I think we're being conservative to some extent in terms of how we've evaluated this position, and we'll know more as we see more well results. But it's a new area, but there are other new areas for us in Giddings, too. There's commonly new areas that we'll be able to speak to with more time. So, we'll study this a little further in order to get a better understanding of what might have happened or what might have surprised us. But I think, you know, we're obviously very encouraged, very enthusiastic about what's happened, just in terms of the results. And as I was driving home last night, I thought to myself, wow, would I rather have had this circumstance about performance where we could lean on it a little bit and driving the better production growth expectations for the year with less capital. Would I rather have these circumstances at $80 oil or would I rather have these circumstances at -$60 oil? And as you can imagine, I'll take it as it is because in this environment, this is working out just fine for us. So, hopefully that gives you a little color.

Most definitely. Unfortunately, I can say I didn't expect that answer. My next question, my follow-up is precisely about what you just touched on in a way. And it's trying to understand what your underlying sustaining capital will look like. Said another way, should we expect the underlying sustaining capital to go down commensurably with your updated 2025 go-forward drilling guidance?

Well, there's a number of factors that would play into that. You know, first and foremost, what we said around our ability to, because of the strong production, and we don't have to be overly heroic on the volume growth this year. So, we're going to defer a handful of completions, call it roughly half a dozen completions, into next year. So, that will provide us with more in the way of flexibility, if you will, not just this year, but also into next year. And so, the cadence of capital just got sort of stretched out or pushed out to some extent. So, I think this year's efficiencies on the capital side also bleeds into benefiting next year's efficiencies too. And in addition to that, talking to what we're seeing a little bit on the OFS cost side, I can't really tell you that in this environment there's any notable upside pressure on pricing on oil field service side. So, things, if anything, could start to fall off a little bit later into this year. So, the capital doesn't feel to me as if it's moving meaningfully higher from the new range that we've talked about, the updated range, the 430 to 470 pace.

Thank you, Chris. Thanks.

Our next question comes from Zach Parham with JP Morgan. Please go ahead.

Thanks for taking my question. I wanted to ask about capital allocation and how you think about that between the gassier and oilier areas of the play. In the current macro environment, could you potentially decide to hold oil volume splat or even potentially let them fall and focus on gassier areas of the play? Just trying to think about how you manage that decision here.

Yeah, thanks, Zach. We find ourselves, frankly, given the broader balance of opportunity set within gettings to almost do whatever we prefer to do to some extent, where the wells that we typically are drilling have a large amount of gas but also come with a good amount of oil as just evidence by some of these more recent wells that we talked about in the first quarter. Oil is sort of going to grow at lower single digits this year, which is sort of what I think is baked to street expectations, 2%, 3%, 4% in that range. I don't see any problem even in this environment with our capability to do that into next year. What I find interesting around your question is that it almost feels like if the oil prices were higher, we'd be talking about just leaning into oil. If gas prices were higher, we'd be talking about leaning into gas. The beauty of gettings is that the returns on the wells, oil, gas, and a mix thereof are very good. It provides us with an outcome that is fairly balanced over time. I don't necessarily have to find ourselves strategically leaning into one particular mix of production or stream. We come and go and we sort of move around the field. Some of it is experimenting or appraising, and some of it is obviously most of it is development, but we find ourselves coming and going into different areas of the field because it's quite large. The footprint is quite large. But strategically, if you will, rather than tactically, strategically, I don't see necessarily shifting in this sort of pricing environment to one versus the other. You'd have to see something far more dramatic, separation between the streams for us to think about doing that right now, and that's not here.

Zach, I'd also add, just like our return of capital to shareholders is very balanced, and so we have a very balanced program throughout the 200,000 acres in Kiddings.

Thanks, guys. A follow-up, I just wanted to ask on the acquisition outlook. You highlighted some on the cash flow statement that didn't come with any production this quarter, but what are you seeing as far as M&A out there in the current market?

Generally smaller, Zach. I mean, we're evaluating some smaller bolt-on opportunities, again, generally that are in our backyard, again, focusing on the chalk and EagleFord where we, again, think we have a competitive advantage through our subsurface knowledge and experience. It's really in these areas where we think the development teams can create better value for the shareholder and for Magnolia over time and improve the opportunity set. But I would tell you, right now, given this heightened level of uncertainty, things have generally slowed down a bit. Maybe said differently, the bid-ask between buyers and sellers has probably widened. I think people have fallen back to a little bit more of a neutral position. The clearing price may work for one, but not necessarily the other.

Thanks, Chris. Thanks, Brian. Thanks.

Our next question comes from Oliver along with TPH. Please go ahead.

Good morning, Chris and Brian, and thanks for taking the questions. Just had one from my end on capital allocation. I know, I mean, just really hoping you all might be able to elaborate on the internal thought process a bit more, just given how dynamic the commodity price environment is today. I know there's the less than 55% of EBITDAX, which acts as a governor on reinvestment rate for you all, and you've highlighted flexibility in your opening remarks. What might we need to see occur to take a closer look at the program in the case commodity risk to the downside does play out? Would this come in the form of incremental completion deferrals, or would we get to the point of maybe a rig dropping off?

Yeah, right now, not that I won't tell you that that thought hasn't pierced my brain or anybody around here as far as curtailing activity, but considering that we're in a good position in terms of the production outperformance and our flexibility around rig operators and our frac group, I mean, we just don't find ourselves in a position to need to do that right now. We have a lot of flexibility, so our plan is, maybe to be more pointed, our plan is not to drop a rig here. We just don't have any reason to do that. We'll continue to monitor the product price environment around supply-demand conditions, and we'll sort of see how things go. And as you pointed out, we have the governor at the ceiling on capital, 55% of gross cash flow. So, you know, I'm not overly concerned about it right now. Could it get worse? Sure. Could it get better? Sure. We'll just have to monitor it. But we have a lot of flexibility. If we needed to, we could defer some things further into next year. Again, as I said, it's about a half-dozen wells, roughly, but it's all within the outlook that we generally provided you on the production. So I don't feel necessarily overly pressured at this point in time. We'll just have to wait and see how things pan out as we move through the year.

Perfect. That makes sense. And maybe just a quick follow-up on service costs. I understand negotiations are likely ongoing, but just anything that you're seeing on either the drilling or frac pricing side of things, can this serve to any sort of softness we're seeing on the product side?

Yeah. I mean, for the second quarter, I would tell you probably overall pricing is roughly flat with the first quarter. I mean, drilling efficiency gains are offsetting some of the small increases on OCTG pricing. And those are, you know, the OCTG steel-related really very small in the scheme of our overall well costs, really as a result of the steel tariffs. But we do have a lot of flexibility within both our rigs and frac service providers. I'm not going to go into the specific terms. On other materials and items, we're probably seeing some relief for sure, as you can imagine on things like diesel pricing. We use a lot of diesel, which has offset some of the small price increases that might be relatively fluid in things like chemicals and valves and other type services. But if this is sort of the picture in terms of what you're seeing on the screen for commodity prices, as we move through the year, you know, back half of the year, you know, the five million dollar handle on oil and, you know, 350 is shunt gas. I wouldn't imagine there's just going to be a ton of upside pressure on pricing. In fact, I would take the other side of it. There would probably be some softness as you go through the back half of the year.

Awesome. Thanks for the time, Chris. Thanks.

Our next question comes from Tim Moore with Clear Street. Please go ahead.

Thanks. And great execution on the quarter and the guidance raise. So for just forgetting, you know, I get asked a lot about this because you have so much untapped potential there and, you know, you're probably planning to do some more peripheral landfringe study work. You know, as Chris has mentioned in the past, you know, those acres lines aren't smooth, they're not homogeneous, and they're more staggered odd shapes. You know, it's probably harder to apply a logical approach for appraisal drilling. But, you know, I'm just wondering, you know, I know Chris started talking about this in his first question response today. If you can, you know, elaborate more color maybe on, you know, how you landed on that acreage, just, you know, maybe with an example, you know, pinpointing where it is and really how you're maybe trying to hop around. If you're going to be hopping around more this year, then maybe you would expect a couple years down the road just because, you know, you've only been working on it for a little bit over a year.

Well, the particular acreage that we highlighted within, you know, where the wells outperformed, I mean, some of this was part of our original area within Giddings going back from the beginning. And part of it was, as we appraised some of it, some of the area, part of it was also acquired after that as part of a package, you know, a couple years ago, at least, I think, two plus years ago. So we continue to scour around for opportunities to fill in holes within our acreage where we think, you know, conditions are ripe for further, you know, development area that looks like the same thing we've been seeing in and around Giddings. So it's a little bit of the extension of the boundaries. I can't do much about, you know, lease lines. It is what it is. But nevertheless, you know, we continue to look for opportunities to acquire or even potentially lease more or whatever to pursue, you know, further opportunities set over time.

That's great. Thanks for that color. And that was it for my questions.

Our next question comes from Noah Hungness with Bank of America. Please go ahead.

Morning, Crystal Bryan. For my first question here, it was, how can we think about, like, the oil cut through the remainder of 25? I mean, with the increased production growth guidance, is it also fair to assume that we'll have some oil growth along with that, some additional oil growth?

I think we'll have, and based on what we're looking at, I think we'll have a little bit of absolute oil growth, oil volumes, a little bit, you know, through the year. On a percentage basis, I think it'll remain relatively stable and quite similar to what we've seen in my bounce around, but within call it roughly a percent or so. But we were sort of 40 percent, so maybe 40, 41 percent in that vicinity. But based on what we're seeing right now in terms of the planning for the wells through the year, it looks like, you know, maybe we'll see a little bit of additional oil in coming quarters, but, you know, fairly stable.

Great. And then on, for my next question, it's on GP&T costs. I think it was a little higher than what we were expecting. As we kind of see natural gas still in a contango for the forward curve, how can we think about GP&T costs trending through the rest of 25 and also into 26, if you could?

I mean, most of the increase that you see, I mean, these things, GP&T tends to move in tandem with gas prices. So generally, you know, the move is in about the same direction, not necessarily linearly, but there's other variables as well that might impact GP&T, but generally in a similar broad direction. So if gas prices should spike or rise further into summer or, you know, as you get more into winter, I would imagine, you know, GP&T would move generally in the same direction and alternatively the opposite would be the case.

Great. Thanks for the call.

This is the end of the question and answer session. The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.