Magnolia Oil & Gas Corporation (NYSE:MGY) Q4 2023 Earnings Call Transcript

Magnolia Oil & Gas Corporation (NYSE:MGY) Q4 2023 Earnings Call Transcript February 15, 2024

Magnolia Oil & Gas Corporation isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good morning, everyone, and thank you for participating in Magnolia Oil & Gas Corporation’s Fourth Quarter 2023 Earnings Conference Call. My name is Andrea and I will be your moderator 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. Please go ahead.

Tom Fitter: Thank you, Andrea, and good morning, everyone. Welcome to Magnolia Oil & Gas’s fourth quarter earnings conference call. Participating on the call today are Chris Stavros, Magnolia’s 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 2023 earnings press release as well as the conference call slides from the investor section of the company’s website at www.magnoliaoilgas.com. I will now turn the call over to Mr. Chris Stavros.

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 2023 financial and operating results. I plan to briefly speak to our results which closed out a strong year for Magnolia and during which we took several actions to improve our overall business. I will also discuss our business model and our core principles in the context of some of last year’s accomplishments, and note how Magnolia stacks up compared to many other EMP companies on several key financial metrics. Lastly, I will provide an update on Magnolia’s 2024 capital and operating plan, which follows the same principles on which the company was founded nearly six years ago. Brian will then review our fourth quarter and full year financial results in greater detail, along with some additional first quarter guidance before we take your questions.

Starting on Slide 3 of the Investor Presentation and looking at some of the highlights. Magnolia ended 2023 on a high note with fourth quarter production volumes of 85,400 barrels of oil equivalent per day, bringing full year 2023 production to 82,300 BOE per day. This represented year-over-year production growth of 16% for the fourth quarter and full year 2023 volume growth of more than 9%. Production at our Giddings asset grew 55% compared to the prior year fourth quarter, reaching 63,000 BOE per day, which included oil production growth of 59%. Giddings production represented approximately 71% of overall Magnolia volumes last year and the Giddings area continues to see operating efficiency improvements in the field, such as fewer drilling days per well and realizing significant gains in stimulation stages per day.

D&C Capital totaled $91 million for the quarter and $422 million for the year, representing 47% of adjusted EBITDAX for the year and leading to free cash flow generation of $413 million, or roughly 10% of our current enterprise value. We returned 74% of this free cash flow to shareholders through our dividend and share repurchase programs, with the remaining allocated to our balance sheet, which helps support attractive bolt-on oil and gas property acquisitions geared toward improving the overall business. Turning to Slide 4, Magnolia’s business model remains unique since it was devised in 2018 with the objective to create a highly investable, attractive EMP business that is enduring and focused on generating absolute per share value over the long term.

As we have often expressed, Magnolia’s primary objectives are to be the most efficient operator of best-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. Our high quality asset base allows for a low reinvestment rate while still providing moderate growth for the business over time. This results in significant free cash flow generation and we strive to return a significant portion of this to our shareholders in the form of share repurchases and a safe, sustainable, and growing dividend. Some of the excess cash may accrue the balance sheet, helping us to opportunistically pursue bolt-on, attractive bolt-on oil and gas property acquisitions that improve the business, which help to sustain our returns and enhance the dividend per share payout capacity.

We continue to adhere to our core principles and believe this is a sound formula for creating long-term shareholder or value for our shareholders. I’d like to spend a moment reviewing how this model has helped us achieve our goals over the past several years and as our operating program has shifted more to our Giddings asset. Slide 5 shows that Magnolia has had one of the lowest capital reinvestment rates compared to most other EMP companies while achieving a superior compound annual rate of growth in terms of production per share over the past three years. This is a powerful combination allowing us to maximize our free cash flow generation. Turning to Slide 6, our corporate level returns or return on capital employed continue to be some of the best in the upstream energy sector, highlighting our strategy of disciplined capital spending, including last year’s success in reducing our well costs and the beneficial impact of our ongoing share repurchases.

Our cost reduction efforts in 2023 helped further support these returns as we were able to meaningfully grow our production per share with capital that was 17% less than what we had expected at the beginning of the year and 8% below full year 2022 levels. Two key elements of our business model are maintaining our low leverage and generating high operating margins. Slides 7 and 8 demonstrate that Magnolia is best-in-class when coupling one of the lowest leverage profiles in the industry with some of the highest operating margins. This is compared to EMP companies of similar size to Magnolia as well as much larger companies and is a testament to our underlying asset quality and the characteristics of our overall strategy and philosophy. Turning to our 2024 guidance shown on Slide 9.

We expect this year’s plan to deliver similarly strong results at current product prices. Magnolia’s capital and operating plan is expected to deliver high single-digit percentage growth this year, or approximately 7% to 9% on both on an oil and on a BOE basis with a capital budget estimated in the range of $450 million to $480 million. This would result in a spending level below 55% of our EBITDAX for 2024 assuming current strip pricing for products. Total production for the first quarter is estimated to be approximately 84,000 BOE to 85,000 BOE per day, which includes production of facilities downtime caused by severe winter weather conditions during a portion of mid-January. Despite the transitory weather impact last month, our production is fully recovered and it is running normally and we are confident in our full year plan and guidance of high single-digit production growth for the year.

We expect first quarter D&C capital expenditures to be approximately $130 million and anticipate this to be the highest quarterly rate of spending for the year. Most of the full year 2024 production growth is expected to come from our development program in our Giddings area and is the main driver and will receive approximately 80% of our overall capital and include some activity on our recently acquired assets. We plan to operate two drilling rigs and one completion crew during 2024 and expect to maintain this level of activity throughout the year. While this activity level is similar to last year’s operating plan, lower well costs combined with improved operating efficiencies allow for more net wells to be drilled, completed, and turned in line helping to support Magnolia’s overall high margin growth.

Most of the development activity will consist of multi-well development pads in Giddings with a smaller amount of development planned in the Karnes area, in addition to some appraisal wells. For this year’s development activity in Giddings, we currently expect to drill multi-well pads with somewhat longer lateral lengths of approximately 8,500 feet. We continue to run a focused business and in an industry where operational execution and financial discipline are essential. The actions we took last year to reduce our well costs helped to significantly reduce our capital, improve our operating margins, and generate additional free cash flow. Together with the acquisitions completed last year, these accomplishments have strengthened our position into 2024 and we expect high single-digit growth, high margin, and high margin total company production growth with our oil volumes growing at similar rates.

We have a strong five-year history of demonstrated operating and financial results and expect our business model to enhance per share value over time. I’ll now turn the call over to Brian to provide more details on our fourth quarter 2023 financial and operating results.

Brian Corales: Thanks, Chris, and good morning, everyone. I’ll review some items from our fourth quarter and full year results and refer to the presentation found on our website. I’ll also provide some additional guidance for the first quarter of 2024 and the remainder of the year before turning it over for questions. Magnolia closed out 2023 on a high note as we continue to execute on our business model. During the fourth quarter, we generated a total net income attributable to Class A common stock of $98 million with total adjusted net income of $108 million or $0.52 per diluted share. Our adjusted EBITDAX for the quarter was $240 million with total capital associated with drilling, completions and associated facilities of $91 million or just 38% of our adjusted EBITDAX and below our guidance.

For the full year, adjusted EBITDAX was $899 million with D&C capital representing 47% of EBITDAX. Fourth quarter production volumes grew 16% year-over-year to 85,400 barrels of oil equivalent per day. For the full year, production volumes grew 9% to 82,300 barrels of oil equivalent per day. During the year, we repurchased a total of 9.6 million shares and our diluted share count fell by 5% year-over-year. Looking at the annual cash flow waterfall chart on Slide 11. We started the year with $675 million of cash. Cash flow from operations before changes in working capital was $872 million, with working capital changes and other small items impacting cash by $59 million. During the year, we paid dividends of $102 million and allocated $205 million towards share repurchases.

We added $355 million of bolt-on acquisitions, primarily in Giddings, and spent $425 million on D&C and facilities capital, and we ended the year with $401 million of cash. Looking at Slide 12, this chart illustrates the progress in reducing our total shares since we began our repurchase program in the second half of 2019. Since that time, we have repurchased 61.9 million shares leading to a change in diluted shares outstanding of over 20% net of issuances. This is one of the largest decreases in the upstream energy space, with the majority of the companies increasing their diluted shares outstanding over the past five years. Magnolia’s weighted average fully diluted share count declined by more than 2 million shares sequentially, averaging 206.5 million shares during the fourth quarter.

We have 9.2 million shares remaining under our current share repurchase authorization which are specifically directed toward repurchasing Class A shares in the open market. Turning to Slide 13, our dividend has grown substantially over the past few years, including a 13% increase announced earlier this year to $0.13 per share on a quarterly basis. Our next quarterly dividend is payable on March 1 and provides an annualized dividend payout rate of $0.52 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 per share payout capacity of the company.

Magnolia has the benefit of a very strong balance sheet and we ended the quarter with zero net debt and $401 million of cash on the balance sheet. Our $400 million of principal debt is reflected in our senior notes which do not mature until 2026. Including our fourth quarter ending cash balance of $401 million and our undrawn $450 million revolving credit facility, our total liquidity is approximately $850 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 due to the substantial decrease in product prices and especially natural gas prices when compared to fourth quarter of 2022. Our total adjusted cash and operating costs including G&A were $10.55 per BOE in the fourth quarter of 2023, a decrease of $1.60 per BOE, or 13% compared to year-ago levels.

The year-over-year decrease was primarily due to lower production taxes in GP&T. Our operating income margin for the fourth quarter was $17.56 per BOE or 43% of our total revenue. The year-over-year decrease in pre-tax operating margins was driven by the significant decrease in commodity prices. On Slide 16, Magnolia had a very successful organic drilling program during last year. The total proved developed reserves at year-end 2023 were 135 million barrels of oil equivalent. Excluding acquisitions, sales, and price-related revisions, the company added 44 million barrels of oil equivalent of proved developed reserves during the year. Total drilling completion capital was $422 million in 2023, resulting in organic proved developed F&D costs of $9.60 per BOE and reflective of our drilling program.

Our organic proved developed F&D costs declined by approximately 40% compared to last year as a result of our well cost reduction efforts and strong well results. Turning to guidance. We expect our 2024 D&C capital spending to be in the range of $450 million to $480 million, which includes an estimate of non-operated capital that is about the same as 2023 levels. We expect first-quarter D&C capital expenditures to be approximately $130 million and expect this to be the highest quarterly rate of spending for the year. Total production for the first quarter is estimated to be approximately 84,000 to 85,000 barrels of oil equivalent per day, which incorporates the impact of production and facilities downtime caused by severe winter weather conditions in January.

Despite this impact, our production has fully recovered and we are maintaining our guidance for high single-digit production growth in 2024. Most of this growth is expected to come from our development program in our Giddings area. Oil price differentials are anticipated to be approximately a $3 per barrel discount to Magellan East Houston or MEH and Magnolia remains completely unhedged for all of its oil and natural gas production. The fully diluted share count for the first quarter of 2024 is expected to be approximately 205 million shares, which is 4% lower than first quarter 2023 levels. We expect our effective tax rate to be approximately 21% with most of this being deferred. Our cash tax rate is expected to be between 6% and 9% for 2024.

We are now ready to take your questions.

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Q&A Session

Operator: We will now begin the question-and-answer session. [Operator Instructions] And our first question comes from Neal Dingmann of Truist. Please go ahead.

Neal Dingmann: Good morning, Chris and team. And guys, another nice print and guide. My first question is on Giddings, specifically. Can you all talk about the recent Giddings acquisitions and how these assets are looking, definitely realizing its early days? And then maybe, Chris, anything we should be thinking about on the development plan specifically there?

Chris Stavros: Yeah, thanks. Good morning. Giddings is one of those fields, old fields, that it sort of just keeps getting better. And my level of confidence now versus, say, five, six years ago is quite a bit better. And a lot of that is born out of the results, obviously, and certainly what we’ve learned and what we’ve been able to do with the field. So the subsurface, and as I said, it’s one of those fields that where you — it’s gone through different phases of its life over the last several decades, and we happened to get involved really prior to it going through this latest phase in utilizing modern frac techniques and design. So where this is headed is we’ve got a sizable position, more than half a million acres, and we’ve done some recent acquisitions, and I think that’s improved our position and will help us learn some more.

There’s some gassier areas of Giddings, there’s some oilier areas of Giddings, but I think the proof is in the pudding in terms of the results having been borne out. When we picked it up with the original acquisition, the field and the asset was producing maybe 10,000 a day, equivalent or so. As I said, it’s producing more than 60,000 a day now, and that will continue to grow. And this is really what the returns — the quality returns that we’ve seen in the business are really, in many cases, a function of the outcome of Giddings. So where does it go? Frankly, I think there’s more for us to go after here and there. I mean, some of them will be a little bit smaller, some things might be a little bit larger, like in similar terms so what we did or size what we did back in the fourth quarter of last year.

We’ll just have to see. I can’t tell you that we’ll go after everything or anything and everything, but we’ll go after some things and we’re starting to integrate the assets that we recently acquired. Early days look good. This particular asset happens to be a bit oilier. The wells that we plan to drill are shallower, several thousand feet shallower, as I said, a little bit oilier with the economics broadly quite similar to Giddings as a whole overall. So I remain real optimistic about our prospects going forward for the fields and what it’s going to mean to Magnolia going forward.

Neal Dingmann: Yeah, definitely love the footprint there. And maybe following up a little bit with Giddings. Noticeable as you pointed out the operating margins are certainly notable. And I’m just wondering when you look at the expanded Giddings results, I mean is that potentially, will that even lead to, do you think, even lower reinvestment rates? Because certainly notable how good your reinvestment rate and as you highlighted the operating margin. And I’m just wondering baked on maybe a higher Giddings plan, could we see even potential increases in this?

Chris Stavros: Yes, that’s a tough one. I think the results are pretty good over three-year, five-year type period. And if you want to say it’s almost through a cycle, if you will. I don’t think it’s going to be meaningfully different. I mean, there might be some things around the edges as we learn more, but I think the outcome, if I had to look out, I think the outcome is not going to be meaningfully different, which I will take that sort of any day of the week.

Neal Dingmann: Absolutely. Thank you, all. Nice quarter.

Operator: The next question comes from Leo Mariani of MKM Partners. Please go ahead.

Leo Mariani: Hi, guys. I was hoping you could provide maybe a little bit more color on the increased activity in 2024. I think in the press release you guys alluded to the fact that be some more wells this year. Is there any way to quantify that? Is it kind of five or six wells and just kind of any detail around any of the splits here? Is it primarily more of a development drilling program? You did mention there would be some appraisals. Is it a fairly similar appraisal split versus last year? And I guess there’s going to be some drilling on the newly acquired acquisition from the fourth quarter. Do you also consider that kind of appraisal drilling, and is it just a handful of wells? Any color around on the kind of complexion of the program this year versus last would be helpful.

Chris Stavros: Yeah, thanks, Leo. I think you repeated some of what I’ve said and answered your own question in some ways. But anyway, yeah, so we’ll probably drill maybe a little more than a half dozen additional wells this year versus last year net wells. Most of that is or part of it anyway is some of the new assets that will be brought or integrated into the plan. Some is just the ongoing development in Giddings. And keep in mind that the average lateral length is a little longer in this year’s program compared to last year. I would tell you also that the working interest in the wells is also a little bit higher. As far as appraisal goes, no, I wouldn’t consider the drilling on the new assets as appraisal in Giddings. But there may be, depending on product prices, there may be some appraisal drilling in Giddings, just to sort of see if we can learn a little bit more around other areas.

So we’ll see how that goes. And so that’s, by and large, some of the color, I would tell you. The Karnes program will be fairly similar to what it had been, not really very different generally.

Leo Mariani: Okay. That’s helpful. And then just do you have any color you might provide on a few of the big-picture expense items? I think that perhaps the new oily asset had a little kind of higher cost. Any kind of range at all you can kind of throw out there if LOEs going to continue to tick up a little bit and maybe DD&A and maybe G&A has not really changed. Is there anything you can have high level on some of those kind of key cost items?

Chris Stavros: Yeah, sure. Well, the new assets, especially the latter acquisition that we did in Giddings, considering that it is oilier in nature. Yeah, there is a little bit more in the way of LOE, as would be common or typical and as we’re also sort of bringing it up to Magnolia standards, if you will. We are owners of the assets where the prior folks might have been viewed as more renters of the assets. So there’s some things that we need to do or probably will do to bring it up to our standards. However, I will tell you that my choice and my view is that we are going to pursue sort of a program to focus a little bit more on LOE broadly through the year to try to get that down a bit. So, as we transition with the new asset into the first quarter, you might see a little bit more in terms of bump in LOE, not very meaningful, frankly, but a little bit.

And then my hope and view is that we’re going to try to attack this and manage it to the point where we could see some decline later into the year.

Leo Mariani: Okay. That’s helpful. And I guess just anything on any of the other costs, is it G&A per barrel still pretty flat, I don’t know if there’s any impact on GP&T from the new asset either, as that pretty ratably flat?

Chris Stavros: Not really. GP&T, actually, I think we’re doing a pretty good job there and we’ll see how that goes. I’ll just say we’re doing a good job around that. G&A, not going to change very much, frankly, at all, not meaningfully on a per barrel basis.

Leo Mariani: Yep. Okay. Thanks, guys.

Chris Stavros: Okay, thanks.

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

Charles Meade: Good morning, Chris and Brian and the rest of Magnolia team there. Chris, I’m at risk of frustrating you. I’m going to ask one more question about the — about your activity on those recently acquired asset…

Chris Stavros: That’s all right. You wouldn’t be the first one.

Charles Meade: Well, maybe I’ll be the best. Presumably, I think you indicated, actually that you guys had a slightly different view of that asset, or maybe you thought you had a differential insight on that asset. And so I’m curious if you could tell us what further activity you have. Maybe you just kind of characterize the number of wells that you’re going to drill, the number of the pads you’re going to drill on that newly acquired asset. And if there’s any aspect of your well design that’s going to test perhaps some of those differentiated ideas that you have, in which case, what’s kind of a timeline for any kind of results or update there?

Chris Stavros: Yeah. Thanks, Charles. It’s a little early days to be too granular-specific around how we are going to drill the well or wells. There will be a handful of wells that will be drilled later this year where we’ll have some results that probably through some of these data — the data sets, you will be able to see over time. I just don’t know. We’re still sort of studying it and looking at prior results to see how it’s gone. We may make some smallish, modest changes going forward, but we are not at the point, frankly, where these are going to be probably more single wells frankly at this stage. So we’re just not quite there yet. Frankly, we closed on the deal, call it three months ago. So we’re still integrating it and devising it, developing it, folding it into the plan. So it’s still somewhat early days.

Charles Meade: Okay. Well, thanks for that added detail. And then a second question. This is about A&D and the Eagle Ford more broadly. How would you characterize the opportunity set for Magnolia? And how much of your attention are you spending on looking at opportunities right around Giddings? And how much of is directed to the larger Eagle Ford? And also [indiscernible] across Texas?

Chris Stavros: Yeah, it’s a fair question. Percentage of my time, pretty meaningful, I mean, because there’s a lot of things out there. And again, as I said earlier, much of this is born out of our own experiences and knowledge and as we gain further understanding of the wells that we drill and directionally where we want to go and what excites us, what is more attractive for us. And I said this to folks before, at the end of the day, we are trying to — and maybe this is why we’re not overly open about what our plans are, but we’re trying to build a little bit of a mosaic around the asset and fill in some of the blanks and improve the business based on some of the quality areas that we see. So we won’t go after everything. It’s not like I say, well, I’d like to own all the acreage everywhere.

It’s not that, but there are some areas that look interesting and will help us and will help the business, where I can see this enhancing the runway, if you will, and provide more sustainability for the business over time. So I think the opportunity set is reasonably good.

Charles Meade: All right. Thanks for that.

Chris Stavros: Sure.

Operator: The next question comes from Oliver Huang of TPH & Co. Please go ahead.

Oliver Huang: Good morning, Chris and Brian, and thanks for taking my questions. Just wanted to hit on the 2024 outlook really quick. I think you all did a great job last year in being able to exceed initial expectations. CapEx 17% lower for nearly inline production volumes. And I know last year is probably a unique year, just kind of given the misalignment to start the year on service costs. But as we kind of look forward into 2024, what are some of the key levers or upside catalysts that you all foresee, or most excited about that could drive better than expected capital efficiency? And also any sort of color on what drives the lower and higher ends of the CapEx guidance range would be helpful as well.

Chris Stavros: Thanks, Oliver. I don’t know how much of a disconnect there was, but we got after this early and I credit our teams both on the supply chain side and on the operations side, drilling completions and working with everyone to make it happen. But it didn’t just happen. It took a lot of work talking with the vendors and creating some linkage between us and them as being true partners and we did benefit from some of the weakness in large gassier fields to the northeast of us, that where activity was slowing up and we saw some benefit from that proximity to us. But it did take a lot of work. In terms of what’s left, we’ve locked in our costs certainly for the first half of the year. So I’m very comfortable with where things are headed in the first half of the year in terms of our outlook.

For the second half of the year, it doesn’t seem to me as if activity is just going to soar away higher. In fact, maybe you sort of see things flat to a little bit lower or softer, considering where gas prices are. It’s not all that pleasant. And so we’ll just have to see. It may provide us with a little bit of wiggle room for the back half of the year, but generally, things feel pretty good. On the specific areas or items, we did a terrific job around efficiencies last year, especially on the completion side and completion — and stages per day. I’d like to think that we could see some improvements on the drilling side and we’ll work towards that with hopefully some efficiencies and maybe something on the cost side as well, but we’ll see. So I hope that gives you a little bit of color.

Oliver Huang: Yeah, that’s definitely helpful. And just a quick follow-up on a comment you made earlier about potentially higher working interest in wells this year. Just wondering if there’s any way to kind of quantify the magnitude of that shift, really just trying to get a sense of how the net lateral footage might have increased on a year-over-year basis?

Chris Stavros: We can get back to you and answer that more specifically.

Oliver Huang: Sounds good. Thanks for the time, guys.

Chris Stavros: Okay. Thank you.

Operator: The next question comes from Ati Modak of Goldman Sachs. Please go ahead.

Ati Modak: Hi. Good morning, team. Thank you for taking the questions. I guess you mentioned there’s still a lot of opportunity in acquisitions in the Giddings area. Just wondering if these are largely smaller acreages or are there entities that are relatively large as well. And what is the level of interest, maybe that those players have to try and replicate what you are doing versus hand the asset over to you? And does that mean that you would be more active in M&A this year versus last?

Chris Stavros: I don’t know what the other operators are looking to do or willing to do or able to do, frankly, if they’re looking to replicate our plan or whatever. I wouldn’t think that this is necessarily going to be a more active year than what we just had in 2023. We are going to — our plan is to digest and integrate some of what we’ve done last year, which was overall a bit of a heavier year in deal-related activity for us, acquisitions. So there is some digestion and integration that needs to occur. So I think if there are some things, they’ll tend to be a bit smaller, but may hopefully pack a punch. And really, again, as I said, fill in that mosaic of what we’ve been trying to accomplish in recent history and going forward. So I don’t think it’s going to be larger, at least that’s not my sense right now.

Ati Modak: Got it. And then anything around the expectations for well productivity in ’24 versus the prior years? If you can talk about oil per foot basis, how should we think about the trends this year?

Chris Stavros: Yeah, I mean that’s been talked about, to be honest, and it’s sort of an evolution of the program in Giddings over time. I mean early days, there were — the population set of wells was smaller, obviously, and much more focused and concentrated within a very, very limited area. And as that’s broadened out, there may have been some movement around the productivity, but frankly, not in a major way or a terrible way. I think that this year’s program and results should yield similar results to what you saw in ’23. I don’t see any major change, frankly.

Ati Modak: Got it. Thank you for taking the questions. I will turn it over.

Chris Stavros: Okay, thanks.

Operator: The next question comes from Nicholas Pope of Seaport Research. Please go ahead.

Nicholas Pope: Good morning, everyone.

Chris Stavros: Hi, Nick.

Nicholas Pope: A quick question on the reserves details that you provided in the presentation. The price-related revisions, just wanted to make sure, is that — is there anything specific there, or is that kind of balanced across the two assets? Is it just the tail of some of those PDP reserves coming off? Just trying to make sure, I understand that $15 million kind of hit the [indiscernible] there.

Brian Corales: Yeah. And when you roll forward from last year, which had significantly higher pricing, you do lose reserves. So the year-over-year change in the SEC required pricing was relatively significant both oil and gas.

Nicholas Pope: So it’s across both assets.

Brian Corales: It’s both assets. It’s both assets. But I mean, just remember, I think we’re at 75% plus of our, or 75% of our production is Giddings. So it’s probably proportionate.

Nicholas Pope: And on the Giddings acquisition, can you be a little more specific, about what was the timing of the close of that acquisition?

Chris Stavros: It was right around mid-November.

Nicholas Pope: Yeah. Okay. That’s all I had. Thanks.

Chris Stavros: Okay. Thanks.

Operator: The next question comes from Geoff Jay of Daniel Energy Partners. Please go ahead.

Geoff Jay: Hey, guys. I was just kind of curious, you talk about the efficiency gains, particularly on the completion side. Can you help understand — help me understand, I guess like, how significant that increase is? And if you’ve sort of looked around and benchmarked that against your peers, and if you think there’s further efficiencies to come this year?

Chris Stavros: We’re looking into that now. I mean we are going through that process right now as we look to the latter portion, or trying to think ahead into the back half of the year on our equipment and cruise, I don’t know how much I can really add on that specific item for you, Jay — Geoff, I just don’t know.

Brian Corales: And Geoff, if — I’ll just maybe add one thing, and Chris talked about a little bit, is we did a really, really good job on stages per day on the completion side. One of the focus is on — more for this year is on the drilling side to improve more of those efficiencies.

Geoff Jay: Right. Got it. I guess when I saw in the press release that the cost of Giddings, well costs were down about 20%. And my curiosity was piqued about sort of how that might sort of break down between efficiency gains and sort of pricing. And I don’t know if you can — if there was a way to you can kind of help me understand the interplay there.

Chris Stavros: Well, a lot of it was, as you know, a lot of it was steel OCTG, but there was — there were meaningful steps in stem and frac. So there are meaningful benefits there as well.

Geoff Jay: Excellent. Thank you.

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

Zach Parham: Yes, thanks for taking my question. I guess first just could you quantify where your leading edge D&C costs are in Giddings? And maybe give us some color on how much cheaper you expect the wells to be on the newly acquired shallower acreage?

Chris Stavros: Yeah, the wells now are running about 1,100 a foot I would say. And that’s about 20% lower than a year ago. And so that — for the longer — some of the longer laterals that we’ll drill this year, that’s maybe $9 million roughly per well. The well costs for the newer stuff, yeah as I said, they’re shallower, quite a bit shallower, 3000, 4000 feet shallower. But you don’t get the exact efficiencies of pad development too. So, that’s sort of what I know right now.

Brian Corales: And Zach let’s — we need to drill one first before we can give you a better answer. But it is shallower, so on a per foot, it should be a little cheaper.

Zach Parham: Got it. Thanks for that color, I guess also wanted to ask on natural gas. Gas differentials have widened out a bit versus both Henry hub and Ship Channel over the last couple of quarters. We’ve also heard some concerns on Ship Channel widening out further given increasing Permian volumes flow into the Gulf. Can you just give us your thoughts on how you expect gas differentials to trend in ’24 and going forward?

Chris Stavros: Yeah. To be honest, I mean, all our gas goes to Ship Channel. We are a price taker. I still think it’s the second probably best hub outside of Henry Hub to deliver your gas. We’re closer to market than the Permian. We have all the infrastructure we need. Is gas in general challenged? Yes.

Brian Corales: Zach, it’s going to be interesting to really see how this evolves in the market. You’ve probably seen already some of the comments from some of the independent producers, the gassier producers here, maybe reducing their activity a bit. And so this is a market and the operators will respond to the economics. So it will be interesting to see that response and to the extent that things are pulled in, that may over time bring things into better balance. So we’ll see.

Zach Parham: Got it. Thanks, Chris. Thanks, Brian.

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

Tim Rezvan: Good morning, guys. Thanks for squeezing me in. I’d like to start on repurchases first. Just trying to understand if we sort of back into like a repurchase amount based on your 1Q shares outstanding kind of information, it suggests maybe a little lower than that $50 million-ish range that you’ve run. Do you think about it as not wanting to have a free cash flow deficit in the quarter? Just trying to understand, kind of, you’ve been pretty methodical with the repurchases. Is anything changing, or is it just because of heavy first quarter CapEx that maybe you’re pulling back a bit?

Chris Stavros: Well, we are not forecasting the share repurchases, really. I mean, I think, if I recall, I think we bought in 2.5 million shares exactly in the fourth quarter, and I think that was about the same, if not exactly the same, as the third quarter. So sequentially, the amount of shares repurchased was the same. The dollar amount might have been a little different because the shares might have been bought in a little bit less expensively, which is fine. I look at the share repurchase, I mean, just a broad comment. I look at the share repurchase program is sort of ongoing and opportunistic, and there might be some shares that come available in the market, and not that I know anything, but if that were to happen, we could certainly lean in.

If I feel as if there’s a disconnect in terms of perceived value, we could lean in. The share repurchase and the dividend are sort of symbiotic in a way. There’s an integral relationship for us with that. The more shares I buy in, the more it supports our dividend payout per share capacity. So that’s sort of how I think about it.

Tim Rezvan: Okay. If you do the math on that 205 million for the first quarter, it seemed a little light. That’s why I was just trying to understand if there’s something there, and I guess there’s not. So thanks, Chris. I appreciate that. And as my follow-up, I thought it was interesting you said you should have a similar oil cut going through 2024. If we look at the Giddings asset in general, you’ve seen oil cuts, call it kind of mid-30s. Is your confidence that you have enough well control in Giddings that you’re confident of the oil views you’re going to be getting from the 2024 program? Is that what sort of gives you confidence in sort of that oil cut staying where it is?

Chris Stavros: Yeah. No, Tim, thanks. I’m pretty confident with this year’s program on the oil volumes if you will. I think we ran in the 41%, 42% mix of oil for the fourth quarter right in that range. If I had to take a view, I think it’ll be somewhat similar through the year. Maybe a little movement, but not all that much. The oil volumes, they’ll grow, as I said, they’ll grow year-on-year for each quarter, and they’ll grow on a similar basis to the overall BOE volume. So I’m pretty confident with that. That’s what the program is designed to deliver, and it’s just in terms of the well control and the confidence in Giddings. Yes, that’s how I feel.

Tim Rezvan: Okay. Thank you.

Operator: The next question comes from Paul Diamond of Citi. Please go ahead.

Paul Diamond: Thank you. Good morning. Thanks for taking my call. Just one quick one for you. As you guys think about Giddings going forward, as far as just the addressable — total addressable acreage and kind of your progress to that, what you see as the right size level you want to be at? Or is that something we should think about as like a single-year effort, or is that more kind of multi-year goal?

Chris Stavros: I see this evolving over the years. I don’t see it necessarily all occurring at once or in a shorter term. The amount of learning that we picked up and experience has been over this five, six-year period, it’s not all going to come at once here for us as a result. So we are still — we have a large position that will — where we’ll continue to learn through our own activity and as an extension of that, we could and likely will pursue some other small opportunities that make sense.

Paul Diamond: Understood. And do you think those smaller opportunities are more kind of blocking out existing acreage? Or are there more kind of further flung areas that you guys are really interested in exploring up there?

Chris Stavros: Mainly the former filling in.

Paul Diamond: Understood. I’ll leave it there. Thanks for your time.

Chris Stavros: Okay. Thank you.

Operator: This concludes our question-and-answer session. The conference has now also concluded. Thank you for attending today’s presentation, and you may now disconnect.