Magnolia Oil & Gas Corporation (MGY) Q3 2021 Earnings Report, Transcript and Summary

Good morning, and welcome to the Magnolia Oil and Gas Third Quarter 2021 Earnings Release and Conference Call. All participants will be in a listen-only mode. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to the Vice President of Investor Relations, Mr. Brian Corales. Please go ahead sir.

Thank you, Chris, and good morning, everyone. Welcome to Magnolia Oil and Gas’ third quarter 2021 earnings conference call. Participating on the call today are Steve Chazen, Magnolia’s Chairman, President and Chief Executive Officer; and Chris Stavros, Executive Vice President and Chief Financial Officer. As a reminder, today’s conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on risk factors that could cause results to differ is available in the company’s Annual Report on Form 10-K filed with the SEC. A full Safe Harbor can be found on Slide 2 of the conference call slide presentation with the supplemental data on our website. You can download Magnolia’s third quarter 2021 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. Steve Chazen.

Thank you. Good morning, and thank you for joining us today. My comments this morning provide a brief update on our business and operations, how we plan to allocate our free cash flow – and how we plan to allocate our free cash flow for the remainder of the year. Chris will then review our third quarter results, provide some additional guidance before we take your questions. Our strong third quarter financial results demonstrates the quality of our assets and the efficiency of our capital program. We continue to execute in our business model, which prioritizes discipline capital spending, moderate production growth, high pretax margins, and low levels of debt. These principles combined with an improved lower overall cost structure, as well as an unhedged production, allowed us to achieve several records during the quarter, including EBITDAX, free cash flow, net income margin, and earnings per share. We generated $143 million of free cash flow after capital outlines and interest on our debt and repurchase 5 million shares of stock during the third quarter, or about 2% of our total outstanding shares for approximately [indiscernible], despite the $79 million allocated this per share value enhancing activities, our cash balance grew by nearly 30% during the quarter to $245 million. For the year-to-date, the largest use of our free cash flow has gone towards opportunistically repurchasing our own stock. So far this year, we have repurchased 22.6 million shares or about 9% of the total shares outstanding. When compared to the fourth quarter of 2020s fully diluted share count. Therefore we have returned 9% to our shareholders in form of share repurchases for the first nine months of this year. Since establishing the share repurchase program in the third quarter of 2019, we have spent approximately $396 million acquiring our own stock and reducing our diluted share count by 34 million shares. Our share repurchase efforts continue to enhance our per share metrics and expect to continue to repurchase at least 1% of our shares each quarter. Magnolia also paid its first interim semi-annual dividend of $0.08 per share during the third quarter, which is secured oil prices under $40 a barrel. We plan to make the remaining dividend payment in the first quarter of 2022, based on our full year 2021 results and adjusted for oil prices of $55. Our total production volumes grew 4% sequentially during the third quarter, as a result of continued strong well performance. Despite lower non-operated activity investing only 30% of our EBITDAX on drilling completing wells. Quality of our asset base is reflected in the continuing overall growth of our production volumes, low reinvestment rate rates, and finding costs and high full cycle margins. We currently have two operated drilling rigs across our assets and plan to remain at this level into next year. At current product prices this level of activity would result in D&C capital program well below our cap of 55% for our adjusted EBITDAX. One rig will continue to drill development wells at our Giddings asset. While still in the early stages development Giddings the results of our drilling program have become more repeatable and increasingly predictable. Second rig will drill wells in both Karnes and Giddings areas, including some appraisal wells in Giddings. We continue to see improvement in our operating efficiencies at Giddings while maintaining well productivity. 2021 development playoff program has averaged four wells per pad with lateral lengths averaging greater than 7,000 feet per well. This compares favorably to the prior year where we average less than three wells per pad with average lengths about 6,000 feet. More wells per pad combined with longer laterals while increasing the average drilling feet per day have helped and driving further efficiencies as Giddings and partly offsetting some materials and oil field related inflation. Our ability to generate annual – moderate annual production growth with strong operating margins together with our ongoing share purchase program and the payment of secure, sustainable and growing dividend are important components of Magnolia’s total shareholder return proposition. I’ll now turn the call over to Chris Stavros.

Thanks, Steve, and good morning, everyone. As Steve mentioned, I plan to review some items from our third quarter results and provide some guidance for the fourth quarter and some initial thoughts for 2022 before turning it over for questions. Starting with Slide 4 in the presentation found on our website, which shows a summary of our third quarter, Magnolia delivered a very strong third quarter 2021 financial and operating results achieving several records. The company had adjusted net income for the quarter of $158 million or $0.67 per diluted share compared to total net income of $116 million or $0.48 per diluted share in the second quarter year of this year. Our adjusted EBITDAX was $221.5 million in the third quarter with total D&C capital at $67 million or 30% of our EBITDAX. Magnolia’s fully diluted share count declined by 6 million shares sequentially averaging $236 million during the third quarter. Total production volumes grew 4% sequentially to 67.4 Mboe/d of oil equivalent per day in the third quarter. Production in Giddings now represents 55% of total company volumes as Giddings has grown by 80% year-over-year. Sequential improvement in our quarterly financial results benefited from higher product prices, especially for natural gas and NGLs, increased production volumes and lower total costs. Product prices have risen further into the fourth quarter and as a reminder, we’re completely unhedged on all our oil and gas production. Looking at the quarterly cash flow waterfall chart on Slide 5. We began the third quarter with $190 million of cash. Cash from operations before changes in working capital was $211 million during the period with working capital changes and other small items benefiting cash by $6 million. Our D&C capital spending, including land acquisitions was $68 million, and we generated free cash flow of $143 million during the third quarter. Cash allocated towards share repurchases with $75 million and we paid our first dividend and $0.08 per share in September or $19 million. Ending the quarter with $245 million of cash on the balance sheet, or more than a $1 per share. Slide 6 shows our cash flow through the first nine months of 2021. For the year-to-date, we generated cash from operations of $528 million in before changes in working capital. During the nine month period, we incurred a $163 million drilling and completing wells. We spent $284 million on share purchases and paid $19 million in dividends. Summarizing our progress during the first nine months of the year, we’ve grown our total production by 11% from fourth quarter 2020 levels reduced our diluted share count by 22.6 million shares or 9% leading to 20% production per share growth over the period. This growth was all organically driven without incurring any debt and while building $52 million of cash. Looking at Slide 7, this illustrates the progress of our share reductions since we began repurchasing shares in the third quarter of 2019. Since that time we have reduced our total diluted share count by 34.1 million shares or approximately 13% in two years. We plan to continue to repurchase at least 1% of our outstanding shares each quarter, and currently have 8.5 million shares remaining under our repurchase authorization. Management’s philosophy is to maintain a strong balance sheet, and we do not plan to issue any new debt. Our $400 million gross debt is reflected in our senior notes, which are not call until next year and do not mature until 2026. We have an undrawn $450 million revolving credit facility in total liquidity of $695 million, including our $245 million of cash. And our condensed balance sheet and liquidity as of September 30 are shown on Slides 8 and 9. Turning to Slide 10 and looking at our cash cost and operating income margins. Our total operating costs and expenses declined by nearly $10 million sequentially and despite the increase in product prices. Most of the improvement was in the form of lower G&A expenses and other associated costs as a result of the termination of the operating services agreement with EnerVest in the second quarter. Our total adjusted cash operating costs, including G&A were $9.66 per boe in the third quarter, representing a 14% sequential decline compared to the second quarter of 2021. Including our DD&A rate of $7.74 per boe, which is generally in line with our F&D costs. Our operating income margin for the third quarter was $27.66 per boe or 60% of our total revenue. Turning to guidance for the fourth quarter. We continue to run two operated rigs across our assets and expect our fourth quarter capital to be approximately $80 million. This is lower than our earlier guidance and primarily due to ongoing efficiencies of Giddings. Total production is expected to be in the range of 68,000 to 70,000 barrels of oil equivalent per day during the fourth quarter. As I mentioned earlier, we are completely unhedged for both our oil and gas productions should benefit from any further improvement in product prices. Oil price differentials are anticipated to be approximately $3 per barrel discount to MEH during the fourth quarter and in line with recent quarters. We expect our fourth quarter 2021 effective tax rate to be approximately 2%. The fully diluted share count is expected to be approximately 232 million shares in the fourth quarter. And we expected to decline further into next year as we continue repurchasing our shares. Looking into 2022, our current plan is to continue to run two operated rigs on our assets and our operated activity should be similar to the level seen during the second half of 2021. One rig will continue to drill development wells in Giddings with the second rig drilling a mix of development wells in both Karnes and Giddings in addition to drilling some appraisal wells at Giddings. This level of activity should generate year-over-year production growth in the mid-to-high single digits. As Steve mentioned earlier, we continue to improve – see improvement in our operating efficiencies at Giddings while maintaining well productivity. Some of these improvements include increased drilling efficiencies up 10% compared to last year, in terms of drilling feet per day, a 14% increase in average lateral lengths per well more than – to more than 7,000 feet and a greater than 30% increase in the average wells per pad, leading a fewer pads. Since we’re still in the early stages of development in Giddings, these improvements should allow us to partially mitigate some of the materials in oil field inflation into next year. To summarize, Magnolia’s high quality assets and capital efficiency should continue to generate strong operating margins and sizeable free cash flow, allowing us to execute our strategy. Our strong balance sheet provides element of security amidst product price volatility, and is also an advantage in creating optionality for us to opportunistically repurchase our shares, pursue small bolt-on accretive acquisitions and pay a safe, sustainable and growing dividend. We’re now ready to take your questions.

Thank you, sir. [Operator Instructions] The first question comes from Neal Dingmann of SunTrust. Please go ahead.

Good morning all. Steve, great quarter by the way guys. Steve, I can’t help, but notice you continue to have very impressive efficiencies that to me, most releasing resulted in this 4% sequential production growth with only about a 30% EBITDA spend and so my question around that is would you suggest the crux of this is coming from Giddings upside or really just, what else should we read into this?

Yes, it’s really driven by Giddings. The current is pretty predictable. Our costs are predictable. Productions reasonably predictable. The variation, running two rigs, you’re going to have some variation, a well gets delayed or starts a week earlier later. It looks like something’s happening and really nothing’s happening, but it’s basically the efficiencies at Giddings. We continue to look for additional opportunities there outside the current area. And we’ll continue to do that in the next year. The only – I don’t know, if I call it disappointment, but the only difference this year is that, now we haven’t had a lot of non-op activity. It’s been much less than historical and so next year and so what’s happened is, we drilled less net well, than we thought we would drill. Generally speaking, the non-op was like running half a rig for the year. And it’s maybe half of that this year, maybe not even that. So, if that continues, we may add a rig sometime next year to make the net wells work to compensate for the non-op. But that’s the only change I see, and that rig would probably be mostly focused on and new opportunities in the Giddings area. We see a number of areas that look interesting. We’ve drilled some wells. We don’t have completely – we don’t have 90 days of results to talk about, but I remain optimistic about it over the next decade or so.

Great points. That’s kind of what I thought on Giddings. And then just to follow up. You’ll continue to, you’ve bought now back quite a fair amount of stock back. And I’m just wondering, given, your stock has gone up like others. Do you still see the, discount when you look at the options to do with the shareholder return, does that still look to be most accretive, most the best use of your proceeds or maybe just talk about that a little bit, given the run that you all have had – you stock?

I don’t – for 40 years, I’ve never talked about the value of the stock. So, I’m not a stock market expert. And if I were, I’d be wrong around half the time. Maybe more, but at least half, because it’s nearly wrong or right. So, I guess it’s 50/50. So the stock is it depends on your view about oil prices. The industry works reasonably well at $60 oil and works almost two well at $85. So, I’m not a believer in $85, but $60 works really well for us. And so I think that the share repurchase makes sense. We actually have a shareholder, a sizeable shareholder and I don’t want him, I don’t have any control over him or don’t know what he’s going to do. But I don’t also don’t want him to be harming the existing shareholders. So, we buy shares and quantity at the same price he gets, which is basically set by the market forces. And that’s worked out for us. I don’t know what our average price about $13, or something. Less than $13 for all the shares we purchased. So, it’s worked out well for the people who bought the stock and the offering and it’s worked out well, I think for the shareholders. Stock’s gone up a lot, that’s for sure. Luckily my wife doesn’t compute this for me. She does count dividends, but I just – I hate to get into valuation, but I think, as a practical matter, once we set the dividend in February, we could fairly easily grow that that dividend 10% a year for a very long time. And for me, that’s an attractive investment. It’s not Tesla or something like that, but it’s a fairly attractive investment. So, and I just think, that’s the way I think about it, how much can we distribute that doesn’t, that we can give and take in my case. And how much can we continue to grow? That the M&A market has not real attractive right now, almost everything is diluted to us. We got a low finding cost and a purchase of PDP production, maybe two or three times our finding cost to go in. And the locations that come with these PDP packages basically wouldn’t need our economic standards for drilling. We wouldn’t drill them, somebody might, wouldn’t be us. So, it makes it very difficult to drill to buy anything in the current environment. We’d find some small pieces here and there and in our existing areas, but other than that. So the share repurchases and dividends for the next few years, I think will be the driving force. And once EnerVest has gotten to whatever level of ownership, if any, that it wants, then we’ll ship to a more dividend intensive strategy.

I guess, Steve you have everybody careful when you do, if your wife is watching those dividends close. Thank you again.

Sure.

Thank you, sir. The next question is from Leo Mariani of KeyBanc. Please go ahead.

Hello. Are you on mute Leo?

Yes. Hello guys. Can you hear me?

Yes. Now we can hear you.

Okay, great. I just wanted to dig a little deeper into Giddings here. Clearly you guys have increased, your ability to drill more wells for pad longer laterals. I know you’ve kind of historically talked about kind of a rough $6 million type well cost. But clearly laterals are getting longer. So, I just wanted to get a sense that maybe you could, give us a little idea of kind of what the cost per foot maybe have done, during the course of 2021. And it sounds like you guys are optimistic that you might be able to continue to reduce those maybe a little, even in the face of inflation. And then just any comments you could make on results in the development area, the 70,000 development area Giddings, I think you guys did say prepared remarks that they’re looking, more consistent these days. So maybe a little more color if you had around that?

Yes. So in the existing area, they look very much like what we showed you before. We drill more well. There really isn’t enough difference to talk about that. It’s a little better, but it’s not – it’s about the same. And because again, we have a repeatable model, so it is designed to do that. It’s not designed for very – large swings. Outside of it, we continue to look for areas. Some of them are a little gassier, but the economics are the same, especially now with gas, reasonable prices…

In NGLs, yes.

Yes, in NGL pricing. So, the economics are basically the same, even though you’re drill a gassier well, because there’s always some oil, fair amount of oil associated with the wells. So, I’m pretty optimistic about that over next year. We were cautious this year on our capital and what we spent, and we’ll be cautious next year, but probably a little less cautious next year than we are, were this year. So, I think the Giddings thing is working reasonable far to the cost per well. We basically overcome the inflation so far. I mean, the inflation is basically steel and labor costs, and the labor costs, I’m really not bothered with. We want good crews. We want the best crews. If you got to pay a few dollars more per hour or whatever it is, or, I’m really not worked up over that. These are small bucks. This isn’t always tell people this is not 3:00 AM, or we got to raise the price of the scotch tape, in order to pay for the stock. We already got the raise, so there’s no question about passing it through. So, I just think that, if it goes up, the total cost goes up, $1 or $2 that’s about all we see right now. I mean, it’s driven by the fundamentals, the well cost. I don’t think we’ll move or very much even with a little longer laterals and stuff, it’s sort of doing what it’s supposed to do, and we’re getting better at it. So, I just, I wouldn’t worry about this for until you get a lot more inflation and a lot more craziness. Now people start, increasing your capital program by a 100% and things like that to capture this, and you put more pressure on the service companies. I think that’s one thing, but with the small program, we have – we can have good crews and manage as reasonable well. Some other company, but 25 or 30 rigs running, it’s just a lot more complicated, but with two or three rigs, that’s the advantage of a small company they’re disadvantages, but that’s the major advantages you get to keep this under control.

Okay. That’s helpful. And just a couple things around some of the comments that you folks made. Steve, you did mentioned potentially adding what it sounded like a third rig in 2022 to offset the fact that there isn’t, much non-op activity just wanted to make sure I understood that. Would that be kind of a partial rig for the years compensate from a lack of runoff?

It’s definite for a short period of time, and we probably would send the whatever you want to call it, the development or exploration or whatever you want call that activity to that rig, because, you you’d be drilling wells or maybe a two wells had with it. And that would be simpler to do in that, and then focus the other two rigs on the pure development. And the idea is, it’s a certain number of net wells in our mind to drill the product – create the production growth we’re looking for. And we’re not getting the net wells, because we overestimated how much this year, overestimated how much the non-op would be. Now, the Giddings wells did better than we thought. So it’s sort compensated for some of that, but we still have a vision of what the net wells ought be. And so the well rig would be, I would get some time in the spring and for a relatively short period of time to just make sure, we drill in the right number in net wells. It’s not going to generate a lot more capital spending. I don’t think. So we’re – spending such a low level we’re only spending, whatever it is, 30% some of our EBITDA, wouldn’t be the end of world to go to 40%.

Yes. And that makes a lot of sense for sure. And then just a couple number clarifications from you guys. Only noticed that in the last couple quarters, cash taxes have started to come in a little bit, still a low level, but they were kind of zero next year. So, I wanted to see if you guys had any thoughts on where those may go. And then also just notice on the oil cut, it was 49% in the second quarter, 46% in the third quarter, what do you guys anticipate that going as we get into 4Q here in the oil cut?

We’ll let them answer about to cut. But as far as the taxes are concerned, if to continue to spend that 40%, 45%, and you have these earnings, which are – our financial statements are fairly accurate, because we’re looking at real finding costs and while we have some tax loss carry forwards and some increased DD&A from the conversion of the B shares, eventually you’re going to pay taxes, it’s not going to be full tax rate, I don’t think next year, but I would think that the cash taxes will go up some next year. I really don’t know how much, but it’s not a, probably not a huge number, but if you only spend 35%, 40% and you’re generating EBIT margins of 50%, 60%, at some point you’re going to pay taxes, which is not the end of the world, it’s better to pay taxes than generate, not operating loss to be honest.

No doubt. All right guys, I appreciate it. Thank you.

I hope that answers the question on the cut.

Yes. I think on the cut, and the oil cut, I mean, part of it is, is for sure, timing, drilling timing and part of it is certainly for this year is a bit of the lower non-op spending and drilling and activity in Karnes that Steve mentioned. And so I think had that come in as we had originally expected, you probably would’ve had the oil cut a little bit higher. And so that’s not to say that, what we’re seeing in Giddings is sort of very strong on the oil cut and relatively better than, what we probably thought early days.

Thanks guys. Appreciate it.

Thanks.

Thank you. The next question is from Umang Choudhary of Goldman Sachs. Please go ahead.

Great. Thank you for taking my question. Just one from me. Steve, you mentioned the sector looks healthy at $60 oil price and oil prices are currently much higher. Would love your thoughts on the macro and your long term oil price expectation of $55, now there’s – there are a lot of moving pieces here on the macro. Say oil prices are higher, longer term. How does that impact your free cash flow deployment between dividends, share repurchase, organic drilling and completions?

Well, I’m sort of return driven, and so if oil prices were say $65 or $70 on a long term basis, rather than my view of around $60. We eventually the EnerVest shares will be gone, they’ll out to whatever level they’re going to be. And so we’re then looking at buying shares in the open market, which is very difficult to buy shares of our stock in the open market at this point. And there’s just not enough volume. And that’s just a fact, so the share repurchase part of it just won’t be executable, what the level that we’re doing now. So it leads really. I mean, there’s only, so number of things you can do as far as raising the capital goes I think spending a lot of money is the road to hell. So, we’re capped at 55% and I might reduce it to 50%. So, I think that’s the road to bad returns. So general, so it only leaves you with dividends. So, I guess that’s your answer.

And then given you have like a cap of 50% towards dividends, right? Like, would that mean that variable dividend would be on the cards once the EnerVest shares are gone?

No, I don’t like ratable dividends, because dividend investors, in my limited experience care about three things. They care about balance sheet quality. Because they want to make sure the dividends safe. They care that the dividends are paid out of earnings. So you don’t pay them out of so-called cash flow, but you pay it out of what you earn. And then finally care about growing dividends. So, if we had some excess, we would just pay a special dividend and, wouldn’t be part of the normal dividend stream. The normal dividend streams, least our working assumption would be that once you see the dividend in February, you can plan on at least a 10% increase in that every year. So, we want to keep that for the standard dividend investor. And if we build too much cash we can pay a special dividend, but it won’t – we’re not going to put a play in there. Again, I’m very cautious about tying payments to things that aren’t related to earnings. This cash – this free cash flow thing is, it’s free cash flow is a difference between your EBITDA and your capital. And so I don’t know what that means exactly. You could spend more money or less money and generate more or less free cash. And I don’t know if that’s permanent or not. And so I looked at this permanent dividend level and the growth in that is the way to, so that investors can rationally look at the company. And if we get build too much cash, we can distribute them in sort one time or sort of thing to sort of distribute the cash. My wife would like that.

That makes a lot of sense. Thank you.

Thank you very much. The next question is from Charles Meade of Johnson Rice. Please go ahead.

Good morning, Steve, and Chris, and the whole crew there. I’d like to go back to the question of the of product mix for Q4, and I appreciate your earlier comments that, that it relates to non-op activity particularly in the Karnes area, which for reasons we don’t need to go into much, it can be difficult to forecast, but are there things – are there things happening in 4Q with your turn in line schedule or other things that that would make it, that would make the mix change versus 3Q? I mean, it looks like there was actually a slight decline on oil quarter-and-quarter, and I’m guessing that, that in, without knowing anything else, I would expect to see that same trend to play out in 4Q especially with the strength in Giddings, but what are the pieces there?

Well, not forget, as you, most of the wells they’re going to be producing in the fourth quarter or producing now, we’re halfway through the quarter. And so whatever we do is probably going to affect the first quarter or the second quarter, more than the fourth quarter at this point. So, I think it’s roughly similar to the third quarter, because, the carryover works that way.

Right.

You lose sight of the fact that, and one or two or three or four or six wells even doesn’t move the thing very much. The other thing is, we’re – while I’m sure some people believe natural gas prices and NGL prices are going to double from here. We are attracted to drilling in gas and NGL areas, because of the profitability is exceptional on those wells. We’ve got a lot of NGLs. I mean, we were getting that. I think $9 of a barrel or something like that for NGLs a year ago, and we’re getting over $40 now. So, I really underestimate the windfall effects of that.

And Charles, we did tell you last quarter that we were steering some of our activity towards the completion of some gassier wells in Karnes corns and some ducks. And so that had an influence over the cut in the third quarter and sort of dribbles into the fourth quarter as well. It did also have a bunch of oil, so they weren’t, but they were generally a little more gassy.

A little more gassy and it was deliberate way of thinking about it, because, I view, $5 gases. It’s a lot of gas in the United States, I don’t know if you noticed. And so, if it sits at $5 very long, you’re going to be a lot more. So despite their hedging.

A lot of hot air in the United States too. But the – but kind of you anticipated it a bit, my second question, you, Steve, you talked about the results at Giddings, becoming not just more repeatable, but predictable and, but maybe a little bit another piece of the picture there is, there’s been some really eye opening, strong well results offsetting your position in Giddings. So, I’m curious as you look at 2022, and you’ve – I guess you’ve already approached a bit or adjusted a bit with the – saying you’re more open to the more gassy areas. How is that playing out between some of these your well results, offset well results coming strong versus the tilt to gassier areas, and how how’s that – how are you guys approaching that? And what should we look for?

Well, the acreage is ours forever or so, locations don’t – or don’t go away. And, we’re – we look at what other people are doing. And, we try to see how that fits in our – into the modeling we have. And if, so we sort of like them drilling their acreage up, because, generally we have offsetting acreage. So, we’re always happy to have somebody prove it up for us. So, from my perspective, we’ll let them experiment and, we can drill it next year or the year after. So, I’m not really, I view it, one of the problems in Giddings historically for us was that there was nobody else drilling, so nobody believed their results. So, we hope these guys drill and, make good money and that would be swell and because we got more acreage than they got by a lot.

Got it. Thanks for that Steve.

Thanks.

Thank you. [Operator Instructions] The next question is from Noel Parks of Tuohy Brothers. Please go ahead.

Hey, good morning.

Good morning. Just had a couple things. And when I was thinking as you look ahead and in your modeling and sort of plan various scenarios. Are we at the point that as you essentially, self-funding your maintenance drilling, are we at the point essentially where the interest rate environment is irrelevant or neutral and, as you look ahead and think about cost of capital as you forecast?

Well, for us, we’re not borrowers of money and when we said, I didn’t even want to borrow the $400 million that we did when we started, I complained about that. So, we got $24 million of interest expense roughly. We could borrow cheaper I guess than that, now if we wanted, but you know, I don’t think, with the kind of returns we’re making even at $60, $65 oil price, I’m not sure leverage is particularly helpful for or anything. And I just, if we don’t – we didn’t have any interest expense because pay more dividends. My wife would like that better. So, I just think that it doesn’t really matter to us at this point, what the interest rate environment is of the extent that the interest rates now oil is about demand and people always want to look at what the Saudis are doing or Russian are doing. And certainly they can muck things up for awhile, if they make an error, but it’s really about demand, and demand is going to be strong in the next year now, I don’t know, what it will be over time, but certainly in the next year, as the economies open up international flying bills, which is a major user of it. So you’re looking for a very strong demand all on oil prices. So, I think for the next some period of time, that’s important, a lot more important than what the fed or somebody does. And it’s the extent that we’re bounded determined to weaken the dollar. But just when we get oil is paid in dollars. And so that we’ll make more dollars. I may not be able to buy anything with it, but, we’ll make more dollars. So, I think this is about the demand you’re in there clearly strong demand growth there at the time. And as a world economy opens up, you’re going to have a lot of demand haul in the Saudis and Russians for their own reasons are feeding to the some of the growth. But frankly my guess is they like $80 oil for $75 oil.

Fair enough. And I’m thinking about the Eagle Ford from the technology standpoint, do you view the Eagle Ford as having essentially caught up technology-wise with the advances, a few years ago when there was a lot of capital flowing into the Permian and less into the Eagle Ford. Do you view the play as having essentially caught up with technology advances from other basins? I guess I’m talking about pre-COVID days when we had a lot more activity or is there still fruit to harvest some gap that, that might still be closed?

Yes. The Eagle Ford will, I’m probably not to talk, but the Eagle Ford itself in Karnes and rest of the play. There’s – in the general play, I think there’s more room. There’s a lot of inefficiencies in the play if you look, while Karnes is extremely well-developed, because the wells were so good. But as you moved to the weaker areas where we’re with your gassier and they’re probably not as efficient as it could be. On the other hand for us where we are – they’re not monkeying with that is not an efficient use of capital. We can put that capital to work in Giddings, or even some of our Karnes stuff and make a lot more money over the next five years. And then try trying to – I’m trying to do some kind of science project in sort of a marginal production.

Okay. Okay, great. Thanks a lot.

Thank you.

Thank you very much. Ladies and gentleman, we have no further questions. And the conference has now concluded. Thank you for attending today’s presentation. And you may now disconnect.