Magnolia Oil & Gas Corporation (NYSE:MGY) Q1 2024 Earnings Call Transcript

Magnolia Oil & Gas Corporation (NYSE:MGY) Q1 2024 Earnings Call Transcript May 8, 2024

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Operator: Good morning, everyone, and thank you for participating in Magnolia Oil & Gas Corporation’s First Quarter 2024 Earnings Conference Call. My name is Megan, 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.

Tom Fitter: Thank you, Megan, and good morning, everyone. Welcome to Magnolia Oil & Gas’ first 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 first-quarter 2024 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.

Chris Stavros: Thank you, Tom, and good morning, everyone. We appreciate you joining us today for a discussion of our first quarter 2024 financial and operating results. I will provide some comments on our first quarter, noting the progress of our development plan so far this year, discuss an important bolt-on acquisition that we recently completed and highlight some actions we’re taking at the field level to reduce our cash operating costs. Brian will then review our first quarter financial results in greater detail and provide some additional guidance before we take your questions. Starting on Slide 3 of the investor presentation. Magnolia delivered a strong first quarter with total adjusted net income of $101 million. In keeping with our consistent business model, we continued our capital-efficient D&C program by spending $119 million or 52% of adjusted EBITDAX, while generating $117 million of free-cash flow.

As part of our goal to return significant portion of our free cash flow to our shareholders, we returned 68% of our free cash through our ongoing share repurchase program and our recently increased dividend payment. Total Company production was toward the top-end of our guidance at 84,800 barrels of oil equivalent per day, representing year-over-year production growth of 7%. Production at Giddings was 61,400 BOE per day, providing overall growth of 17% compared to last year’s first quarter, including oil production growth of 16%. Total company oil production during the quarter was ahead of expectations coming in at 37,500 barrels of oil per day, benefiting from strong well performance, activity in Karnes and solid performance from the assets we acquired late last year.

We had planned for this year’s program to be a little oilier than last year and our first quarter production provides some early evidence of that plan. Last week, we closed on a very meaningful bolt-on acquisition of oil and gas properties in the heart of our Giddings acreage. These assets were acquired from a private operator for $125 billion, have similar attractive operational financial characteristics to our core acreage position at Giddings. As I’ve often mentioned, the key part of our strategy is to use some of the excess cash generated by the business to seek out attractive bolt-on acquisition opportunities with the goal of making Magnolia better, not by simply replacing the oil and gas that is produced, but to improve the future opportunity set of our overall business and enhance the capability and sustainability of our high returns.

This latest bolt-on acquisition adds new high-quality acreage that is contiguous to our existing core footprint in Giddings, while also increasing our working interest in some of our current acreage. The transaction leverages the significant knowledge we have gained through operating in this field and extends our deep inventory of high-return development opportunities in Giddings from both new locations and incremental working interests. As shown on Slide 4, the majority of the properties are located in the core of Giddings with acreage in Washington, Lee and Fayette Counties, representing an additional 27,000 net acres spanning over 80,000 total gross acres. The properties include a relatively small amount of base production of approximately 1,000 BOE per day and about 35% oil with Magnolia operating most of the volumes.

This is an ideal acquisition for Magnolia, which significantly enhances our position in Giddings and strengthens the Company moving forward. Magnolia continues to operate two drilling rigs and one completion group with the majority of this year’s activity planned in Giddings. Our full-year 2024 guidance for D&C spending remains unchanged and is expected to be in the range of $450 million to $480 million. Following on last year’s success in reducing our well cost by nearly 20%, our drilling and completions have gotten off to a strong start in 2024 and we continue to drive further operating efficiencies. While this year’s program includes drilling somewhat longer laterals, we have realized considerable recent improvement in reducing our drilling days per well.

Lower well costs combined with improved operating efficiencies allow for more wells to be drilled, completed and turned-in line during 2024, helping to support Magnolia’s overall high margin growth. As I mentioned earlier, we expect this year’s development program to be oilier than last year and our strong first-quarter oil volumes support the plan. We anticipate that this year’s oil production should remain resilient as a portion of our activity will focus on some of the oilier assets acquired last year. Some of our drilling activity leaned away from natural gas early in the year due to very weak prices, and we expect that our natural gas production should reassert its growth as the year progresses with the view that gas prices would see some recovery later in the year.

Lastly, our operations and supply-chain teams have initiated a field-level optimization and cost-reduction program throughout our assets. Part of these efforts will employ improved field management systems that will increase efficiencies and optimize processes across the field and targeting such areas such as contract labor utilization, surface repair and maintenance and procurement, just to name a few, while capturing synergies from the acquired assets. These and other initiatives to lower our cash costs are expected to deliver a 5% to 10% reduction in our cash LOE per BOE during the second half of the year compared to the first quarter. As Magnolia has grown and learned while operating our assets over the past six years, we believe this is an appropriate time in our evolution to embark on this program.

Our goal is to improve on our track record for generating high operating margins, while providing additional free cash flow to either return to our shareholders or efficiently reinvest in the business and these actions should help us achieve these objectives. I’ll now turn the call over to Brian to provide more details on our first quarter financial and operating results.

Brian Corales: 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 2024 and the remainder of the year before turning it over for questions. Beginning on Slide 5, and as Chris discussed, Magnolia had a solid first-quarter across the board. During the quarter, we generated total GAAP net income attributable to Class A Common Stock of $85 million with total adjusted net income of $101 million or $0.49 per diluted share. Our adjusted EBITDAX for the quarter was $228 million with total capital associated with drilling, completions and associated facilities of $119 million or 52% of our adjusted EBITDAX and almost 10% below our guidance.

First-quarter total production volumes grew 7% year-over-year to 84,800 barrels of oil equivalent per day and our diluted share count fell by 5% year-over-year to $204.3 million shares. Looking at the quarterly cash flow waterfall chart on Slide 6, we started the year with $401 million of cash. Cash flow from operations before changes in working capital for the first quarter was $218 million, with working capital changes and other small items increasing cash by $6 million. We spent $27 million on bolt-on acquisitions, primarily in Giddings, paid dividends of $27 million and allocated $51 million toward share repurchases. Total capital was $121 million and we ended the quarter with $399 million of cash and relatively flat from year-end 2023 levels.

Looking at Slide 7, this chart illustrates the progress in reducing our total outstanding shares since we begun our share repurchase program in the second half of ’19. Since that time, we have repurchased 64.3 million shares, leading to a change in diluted shares outstanding of over 20% net of issuances and supports our goal of improving our per share metrics. Magnolia’s weighted average fully diluted share count declined by more than 2 million shares sequentially, averaging 204.3 million shares during the first quarter. We have 6.9 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 8, 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 June 3 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 payout capacity of the Company. Magnolia benefits from a very strong balance sheet and we ended the quarter with approximately zero net debt and $399 million of cash. Our $400 million of principal debt is reflected in our senior notes, which do not mature until 2026. Including our first quarter ending cash balance of $399 million and our undrawn $450 million revolving credit facility, our total liquidity is approximately $850 million.

Our condensed balance sheet as of March 31 is shown on Slide 9. Turning to Slide 10 and looking at our per unit cash cost and operating income margins. Total revenue per BOE declined year-over-year due to decrease in natural gas and NGL prices when compared to the first quarter of ’23. Our total adjusted cash operating costs, including G&A were $11.86 per BOE in the first quarter of ’24, a decrease of $0.79 per BOE or 6% compared to year-ago levels. The year-over-year decrease was primarily due to lower production taxes in GT&P. Our operating income margin for the first quarter was $16.15 per BOE or 39% of our total revenue. The year-over-year decrease in our pre-tax operating margin was driven by the decrease in commodity prices and higher DD&A rate.

Turning to guidance, we are reiterating our expected 2024 D&C capital spending to be in the range of $450 million to $480 million, which includes an estimate of non-operating capital that is about the same as 2023 levels. Total production and oil production are still expected to grow high-single-digits on an annual basis. For the second quarter, our D&C and associated facilities capital expenditures are expected to be approximately $120 million to $125 million with total production for the second quarter estimated to be approximately 89 million-barrel — sorry, 89,000 barrels equivalent a day. Oil production — oil price differentials are anticipated to be approximately a $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 second quarter of 2024 is expected to be approximately 203 million shares, which is 4% lower than second quarter 2023 levels. We expect our effective tax rate to be approximately 21% and with increased oil prices, our cash tax rate is expected to be approximately 9% to 10% for 2024. We are now ready to take your questions.

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Q&A Session

Operator: [Operator Instructions] Our first question comes from Neal Dingmann with Truist. Please go ahead.

Neal Dingmann: Yes, we’ve always talked about the returns and breakeven. I’m just wondering, could you talk about the latest breakeven? When you look at Giddings right now, I’m just wondering, could you talk about the — how that breakeven maybe compares to Karnes or Chris, just maybe how you’re thinking about the returns there these days versus even a year ago?

Chris Stavros: Yes. Good morning, Neil. Thank you. Yes, you know, I certainly wish gas prices were a little bit better. But frankly, all-in-all the Giddings wells have better full-cycle returns than the wells we drill and complete in Karnes. I mean that’s just the basic frank thoughts around it. The Giddings well certainly in our core area and most of the wells we drill often pay out in a year or less. And we’ve talked about this quite often that they produce more oil over their life than a typical Karnes well. So the Giddings well returns are very high and even in this environment. And so you wouldn’t do anything necessarily differently in terms of skewing or slanting more activity to Karnes per se, just to sort of capture return and the Giddings wells also have a shallower rate of decline. So I think it benefits us all-in-all.

Neal Dingmann: And Chris, how much have you brought down the breakevens as your operational efficiencies have continued?

Chris Stavros: Well, our well costs have come down quite a bit and much of that was captured through our efforts last year by working with our service providers, material vendor. And as I said this before, we probably brought well costs down about 20% and some of that is continuing into this year. So the well costs are currently probably 1,100 a foot, more or less and probably coming down a little bit further. We’ve made some inroads, as I said too on drilling faster. So things are just working out real well on that side. So the efficiencies and the breakevens are sort of continue to come down a little bit.

Neal Dingmann: Great to hear. And then maybe just a quick second one on M&A. Specifically, I really like your comment on how the bolt-ons you’re not simply just replacing the oil and gas, but improving the opportunity set. I’m just wondering, if you could give us a bit more color on the latest $125 million deal, maybe what that did as far as terms of location or how that did improve your opportunity set there?

Chris Stavros: Yes, sure. Yes, we said this for a long time and I know Steve used to say it, but it’s true. The way to make money in the business, in the oil business is to either guess right on the commodity price or acquire attractive optionality at a low-cost or maybe even for free. When it comes to PDP deals, you’re going to pay full value or strip prices for that at the very least. And I’m — yes, there’s not much to that in terms of real upside. I’m not looking to inherit a lot of production and have to overcome a decline rate. So this particular deal, this is a sort of a great fit in terms of what we look for as far as our bolt-on strategy, specifically lower PDP volumes, but very importantly, significant high-return development opportunities at a low cost and with potential upside.

And so we showed this on the map or at least tried to, as I said, a lot of new acreage and increased our working interest in existing acreage in a very, very productive area of Giddings right next door to where we’ve been busy with our current development. So this transaction represents a unique opportunity and I’m very confident that it provides us with a minimum of probably a couple of years of high-return net drilling locations and at our current pace of drilling in Giddings. So I think that there’s more here than meets the eye and frankly more than — more bang for the buck.

Neal Dingmann: Fantastic. Thanks, Chris.

Operator: Our next question comes from Leo Mariani with ROTH MKM. Please go ahead.

Leo Mariani: Hi, guys. Wanted to start off with just focusing a little bit here on oil cut. So oil cut was definitely, I guess, stronger-than-expected in the quarter. Just wanted to kind of get a sense of how you kind of see that playing out. I think it’s kind of the highest quarterly oil cut you’ve had in a couple of years here. Do you think that can kind of get maintained throughout the course of the year? I know some of the focus a little bit more on some of the oily drilling or do you see that maybe starting to soften as we get later in the year?

Chris Stavros: Yes. Thanks, Leo. So for the first-quarter oil production, we, obviously, as I said, saw good performance, strong overall well performance across the business, strong performance from the assets that we acquired. We had some oilier Karnes activity that came online during the quarter. This year’s development plan will be oilier than last year and our first quarter volumes on oil support that. Some of the drilling, as I said, leaned away a little bit from natural gas early in the year, but that should recover and reassert itself, as I said, as the year moves forward. But I also expect that this year’s oil production is going to remain pretty buoyant as a portion of our activity is going to focus on some of those oilier assets that we acquired.

So rather simply — rather than simply focusing on the oil mix or percentage, I would characterize our absolute oil volumes as having the ability to remain pretty robust throughout the year. So I hope that gives you a little color. It’s going to be a little lumpy as we move forward quarter-to-quarter as it typically is, but I think oil is going to be pretty good and that was part of the plan.

Leo Mariani: Okay, I appreciate that. And then just going back to the acquisition that you did here. So it sounds like you guys are pretty excited about it. Certainly noticed that you’re not changing your production or capital guide for the year. I know it adds kind of a small amount of volumes, but that kind of maybe implies that you’re not doing a whole lot in terms of D&C on the asset this year. Just kind of want to get a little better sense for what your plan is. Is it something you’re going to integrate in the program next year in terms of drilling? I know some of this is just additional interest on what you already own, but presumably there’s some new stuff to drill as well? And then just do you see other opportunities like this out there? I guess it’s kind of your second decent little bolt-on in the last six months. So just trying to get a sense of what the plan is going forward.

Chris Stavros: Yes, thanks. That’s a lot packed in there. So on the guidance, part of my job is to manage the external expectations and within our capability of delivering solid results. Right now, things are going rather well on the drilling and completion side. Yes, the production volumes acquired from the deal represent what the assets are currently producing and since we’ll only own it for two-thirds of the year, the overall production doesn’t amount to very much. And actually that’s just fine because we didn’t acquire these properties for the PDP. We acquired it for the high-quality undeveloped opportunities, which, as I said, I think are quite significant in my view. Maybe there’s a touch of conservatism here or the way I think about it, maybe a little bit of Murphy’s law on me, but I prefer not to get too cute with the guidance.

So with that in mind, I think our total production and oil production should grow in the high-single-digits this year or maybe even the high, high-single-digits, but certainly high. And on the acquisition itself, it’s hard to time these things, these types of opportunities. This is something that it started evolving really last year. It was unique from a private operator. I’m not going to pretend to speak for individuals who’ve made very personal decisions, but started to take shape last year and it took a lot of effort and cooperation by both parties to make it happen and that’s about all I have to say about the process. But yes, sure, I hope there would be or could be opportunities like this one, that would be great. The objective is to sort of do these things within our capability of managing them that are not necessarily size for size sake, the objective is to make us better, not necessarily bigger and to sustain ourselves with our high margins and our business model profile for the long-term.

And so that’s how we look at things. I think the acquisition itself will get folded into our broader Giddings program because that’s what it is. It just will fold in some wells this year will fold in more wells next year. It’s — that it will be — it will look like Giddings because that’s what it is.

Leo Mariani: Okay. Thanks for the color. Appreciate it.

Chris Stavros: Sure.

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

Charles Meade: Good morning, Chris and Brian, and everyone on the Magnolia team there. Chris, I want to take a another run at the acquisition. And I’m wondering if you could characterize for us the — how developed it is in the target zones you’re going after? And then maybe — and that might differ if you have more than one target down the column, you know, how undeveloped is it in your targets? And then how many net locations do you think you’re bringing in?

Chris Stavros: Well, it’s not very developed. In fact, I would characterize it as frankly undeveloped. It’s about as undeveloped as you can imagine. So there’s low-hanging fruit here, there’s all upside. And I — that’s about all I can say as to why. But anyway, so there’s a lot of potential opportunity for ourselves here. It’s unique, as I said. Yes, I’m confident in the fact that we’ve added a couple of years’ worth at our pace of net locations because we can see this and we understand it real well from a subsurface perspective and our ability to drill wells that look very similar to some of our better-executed pads and wells in some of the core areas of Giddings. So you got to tie me down. I’m pretty excited about the fact that we were able to pull this one-off. And it’s quite good. So I don’t know how much more I can say, but it’s — at our pace currently, it’s about a couple of years’ worth of drilling.

Charles Meade: That’s a helpful data point. Thank you for that, Chris, and that’s it from me.

Operator: The next question comes from Oliver Huang with Tudor Pickering Holton Company. Please go ahead.

Oliver Huang: Good morning, Chris and Brian, and thanks for taking my questions. As you all continue to bolt-on in the Giddings area, which you’ve acknowledged having better relative economics to the inventory that remains in Karnes, generally speaking, how should we think about the mix of capital allocation between Karnes and Giddings versus that 20-80 split that you’re all running this year on a go-forward basis?

Chris Stavros: Yes, thanks for the question. I think it’s going to be about that more or less. I don’t see it changing dramatically. And, you know, otherwise, and I’m speaking operated, non-operated and on Karnes and it’s a little hard for us to predict, but generally that 80-20, I think sort of applies here for a while as far as I can see right now.

Oliver Huang: Okay, that’s helpful. And maybe just to touch on deficiencies a little bit more. You previously kind of mentioned how the frac side of things was a big driver of lower well costs last year and that the drilling side is a much bigger focus for 2024. Just wondering, if you could maybe talk to the progress you’ve seen to date? And also when we’re kind of looking at the Q1 CapEx coming in a little bit below your guidance, if there’s any color behind if it was more well cost-efficiency driven, working interest or just more of a timing aspect?

Chris Stavros: I think there’s certainly some timing to that, which is really why the second quarter — some of the capital got shifted into the second quarter. So there’s always going to be little matters around timing for that. And frankly, we could see more of that. It just sort of depends. I think you know that the numbers that we have been borne out up to now in the first quarter and the guide for the second quarter sort of plus or minus what it looks like right now. But that’s without trying to bake in potential improvements that we can continue to make, if we’re drilling faster that has an outcome to it to some extent. And so there may be more that comes into play or into the program. This is a good thing, by the way.

I mean, it creates more cushion for us and optionality for the remainder of the year. So I think that works out favorably for us and I’m — that’s fine. And the weakness or the softness in natural gas prices has certainly sort of continues to have an impact on materials pricing, OCTG is sort of still softish and has probably seen single-digit price softness into the second quarter. I tell you rig and pressure pumping crew availability is ample. Operators are competing on price, quality, performance. And as I said, I think that we’ll see some of these small benefits get factored into those well-cost numbers that I quoted earlier.

Oliver Huang: Makes sense. Thank you for the time, Chris.

Chris Stavros: Okay. Thanks.

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

Zach Parham: Hi, guys. Thanks for taking my question. First, just wanted to ask on the cash return program. You’ve been pretty consistent for quite some time with the buyback. But you’ve got a lot of cash on the balance sheet. At some point, could it make sense to accelerate the buyback and use some of that cash to buyback stock?

Chris Stavros: It could. I mean, I like the consistency of the program and of the model. So I don’t want to get too specific on pointing out a number, but it feels like in this sort of range of pricing — product pricing, you’re looking at sort of a two-thirds return of free cash flow and a mix of share repurchases and the dividend. There may be some flexibility on the dividend — on the share repurchases rather just given our somewhat price sensitivity around that. We’ll — if the stock is sort of weak for some particular reason that we can’t necessarily justify or figure out, we’re happy to lean in or not. And so we’ll just sort of see how it goes. I’m not favorably inclined to just keeping a bunch of cash on the balance sheet just because, I joked about this, we’re not a bank.

It sort of weighs on our returns and I’d rather put it to use to generate higher returns if we can. Right now, having no real net debt is, obviously, very comfortable and it makes people feel better, but you don’t necessarily need to have that much cash sitting around.

Zach Parham: Got it, thanks for that color. And my follow-up just on LOE, can you give us a little more detail on what you’re doing to reduce LOE and maybe any thoughts on what LOE looks like in 2Q before declining in the back half of the year?

Chris Stavros: Yes, we’ve already started on this. I mean, we’re first talking about it now, but we’ve already been at it here for a little bit. And so my hope is that you’ll start to see some improvement even sooner than in the back half of the year and frankly into the second quarter. But I think the larger improvement gains should be more evident in the third and fourth quarters of the year. But I’m very confident that the first quarter would have been the highest on cash operating cost per BOE for the year. As I said, we’ll employ things like some of this field management systems that will lead to improved efficiencies and optimization across the field, well optimization, contract field labor, surface repair, maintenance, procurements, synergies from the acquired assets.

I mean, there’s a lot of low-hanging fruit that I think we can capture. So this is — you could call this a little bit like spring cleaning. We’ve been at this for a while in terms of operating both Giddings and Karnes over the last six years. And we’ve learned and grown with it, but I think this is an appropriate time for us to pursue it. And we’re in a portion of the cycle that I think is a little stronger. And so the organization can look at areas to improve in a more thoughtful way rather than being forced to make more knee-jerk reactions or draconian decisions if we were in a much weaker environment. So I think this is a good time to do it. Our field folks have embraced it and everybody is onboard, and I think it’s starting to work out pretty well.

Zach Parham: Got it. Thanks, Chris.

Chris Stavros: Thanks.

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

Noah Hungness: Sorry, I was on mute. I just wanted to ask a quick question here on the deal again. It looks like it fills in a lot of acreage gaps. Does it — does this allow you guys to potentially have longer laterals than the 8,500 feet that you guys are drilling this year or does it unlock potentially stranded acreage? And then also, are there any contingency payments associated with this deal similar to what we saw with the November — the deal that closed in November?

Chris Stavros: No, there’s no contingency payments whatsoever. The cost of the transaction is as we stated. The answer on longer laterals and unlocking additional acreage, yes, and yes. I’m not going to tell you that all the wells or locations will be longer than what we’re currently drilling this year on average, which will be about 8,500 feet. But certainly there would — I expect that there will be some longer for sure. We’re taking a closer look at that in terms of what it may be able to unlock as far as lease lines, et cetera. But, yes, I think there’s more opportunity for that.

Noah Hungness: Great. And then just switching over to the oilier assets you guys are looking to drill later this year. How do those economics compare to core Giddings today, just given how the forward curve has moved up? And could you give any color on maybe when you think those wells will come online 3Q or 4Q?

Chris Stavros: Yes. I think you can probably be able to see that later this year in the datasets that are out there. I — there’ll be some data, some production that you’ll be able to quantify. As far as the returns, I mean, it’s very oilier obviously than core Giddings or general Giddings. But again, an important point is that these are shallower wells, they’re 3,000 to 4,000 feet shallower than our typical Giddings well. So the D&C costs are lower. So the economics, frankly, are very similar to what we see in the core Giddings.

Noah Hungness: Great. Thank you. And I’ll hand it back there.

Chris Stavros: Thanks.

Operator: Our next question comes from Ati Modak with Goldman Sachs. Please go ahead.

Ati Modak: Hi. Good morning, team. Just a quick question on the cost reduction. Sounds like you’re beginning with your cost reduction plan at this point and obviously, there are a lot of your peer that have been doing several things overtime to reduce costs. So maybe help us understand where you will be after this initial phase on that journey versus others and so that — just so that we can gauge how much room there is to go after this?

Chris Stavros: Well, I think, the 5% to 10% is a very good starting point. We’ll sort of see how it goes. We — as I said, we haven’t really done a lot of this. So I think there’s low-hanging fruit. We’ve been at this six years and I was joking with the guys. I mean, it’s almost like taking a spin in the dryer where you — the longer you’re in the dryer, the more lint you pick up and occasionally you got to shake off the lint. And so, there’s a lot of things that we can go after and we’ve accumulated more understanding of the assets. We’ve obviously drilled a lot of wells in Giddings. We have a better understanding of it. There’s some, I think, synergies with the focus that we have within our core and the application of some field management systems that will really help us out here in managing some of the processes in the field.

So we’ll see how things go, but I am optimistic that we’ll start to see some early gains here before the back half of the year, and we’ll just continue to see how it goes. The objective here is really to improve our operating margins at the end of the day. I mean, the cash cost will come down, the operating margins would pick up all else equal and provide us with better earnings and more free cash flow. That’s really the objective.

Ati Modak: Awesome. And then, I guess, taking that as queue, like how does this plan tie into the long-term sort of efficiency objectives — capital efficiency objectives? And as you free-up more capital, how should we think about that allocation strategy?

Chris Stavros: Well, this is a less of a capital exercise as it is really more of a field exercise. At the end of the day, both of the actions or activities amount to money. So the capital side just gets folded into your F&D costs and your DD&A. And so that at the end of the day is your biggest cost. And so the more you can do on your well costs will provide greater drilling efficiencies over time and more-and-more free cash flow as well, requiring a lower reinvestment rate with same outcome. So they’re clearly tied together, but we’ll look at some things, there’s probably some overlap in terms of things that we were able to do well on the capital side that could — that may apply in terms of what we’ve learned that we could apply in the field.

Ati Modak: Got it. I appreciate that. I’ll turn it over.

Operator: Our next question comes from Hanwen Chang with Wells Fargo. Please go ahead.

Hanwen Chang: Thanks for taking my questions. I want to follow up on the investment rationale behind the new Giddings acquisition. Could you perhaps provide some colors on some of the key valuation metrics of the acquisition? Thank you.

Chris Stavros: Yes. Well, you didn’t get a whole lot of volumes. So I’d imagine if you back out just the value of the current PDP, you’re looking at 3,000 to 3,500 an acre something like that. I’m not sure what else I can say I think that’s pretty attractive frankly.

Hanwen Chang: Got you. And do you have any preferences regarding oil ratio for future acquisitions? Thank you.

Chris Stavros: No, I don’t look at it like that. I look at it just in terms of how it’s going to improve our business and financial outcome and how it sort of continues to extend the capability of managing our model — our business model, which is completely designed around being the most efficient operator and drilling the best wells at the lowest cost to provide as much free cash flow that we can return to shareholders and reduce the share count as we have over time and we don’t — we’re not looking to increase our debt levels or we’re not sellers of stock. And so we’ve done everything we’ve done pretty organically here just through cash generated by the business. So that’s the plan.

Hanwen Chang: Thank you.

Operator: Our next question comes from Sean Mitchell with Daniel Energy Partners. Please go ahead.

Sean Mitchell: Thanks for fitting me in, guys. Sorry, I was on mute. Congrats on the deal. Deals are not easy to come by these days. So congrats to you guys for getting something done. Several of your peers are doing refrac work and I think there’s more buzz today than there has been in the Bakken and the Eagle Ford. How are you guys thinking about this opportunity, if at all?

Chris Stavros: Yes, it’s more in the if at all category.

Sean Mitchell: No, that’s fair. I mean…

Chris Stavros: I appreciate the question, Sean. I hear you. It’s way, way too early for us to really think about this for us in a broad way. These are early science projects, frankly, there’s lots that we are focusing on far and away from things like that. It’s too much of — too many things for us to do and drill before we ever get to that. So I just can’t see that in our mix in any substantial way for a long time.

Sean Mitchell: Yes, fair enough. And maybe a follow-up. On the bolt-on, I think, I probably know the answer, but were these guys running a rig or no?

Chris Stavros: They were not to my knowledge.

Sean Mitchell: And then of the two rigs and one frac crew you guys have today, remind me, are those on spot or do you guys have those contracted?

Chris Stavros: Contracted.

Sean Mitchell: Okay. Very helpful. Thanks, guys.

Chris Stavros: Okay. Thanks.

Operator: Our next question comes from Paul Diamond with Citi. Please go ahead.

Paul Diamond: Thank you. Good morning all. Thanks for taking my call. Just a quick one on kind of the opportunity set you see all or you all still see in Giddings. How should we think about that geographically? Is that more north of Lee, more Fayette, Eastern Washington just — kind of just a generalized scale of that similar to bolt-ons or a lot more of the smaller-type opportunities still available?

Chris Stavros: Well, we have a lot to work on in the areas that you mentioned for sure. And there’s a lot of acreage in addition to that elsewhere, other counties within the Giddings field and Giddings proper. So we still will continue with some appraisal work to have a better understanding and better define some other areas that frankly has worked very well and led us to seek out new opportunities, whether for bolt-ons or just areas that we could drill with strong economics. So I think it’s still relatively early days. You can’t get to everything all at once. It’s — some of it is just going to fall into a question of how much money there is available to us in any given time period, in any given year and the plan that we have to execute. So you can’t do everything. We’ll get to it overtime, but there’s a lot that we can look at overtime.

Paul Diamond: Understood. And how do you — and how is the scale of those opportunities? Are they more like small ground game-type stuff or are they similar-sized bolt-ons the one done this quarter?

Chris Stavros: There are. I look at this and say, I mean, it would be unfair for me to say that you’re going to see something like this that we just did again, not this specific type of transaction, but there are potentially other small fill-ins, small working interests or just fill-in properties to help round out areas that we like and are working well for us.

Paul Diamond: Understood. Appreciate the clarity. I’ll leave it there.

Chris Stavros: Thanks.

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