Magnolia Oil & Gas Corporation Class A

Good day and welcome to the Magnolia Oil & Gas first quarter 2020 earnings release and conference call. Today all participants will be in a listen only mode. Should you need assistance during today's conference, please signal for a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touch tone phone. To withdraw your question, please press star then two. Please note that today's event is being recorded. At this time, I would like to turn the call over to Brian Corales. Please proceed.

Thank you, Chris, and good morning, everyone. Welcome to Magnolia Oil & Gas' first quarter 2020 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 meeting of the federal security 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 two of the conference call slide presentation with the supplemental data on our website. You can download Magnolia's first quarter 2020 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. Steve Chazen.

Thank you, Brian. Good morning and thank you for joining us today. My comments will focus primarily on how Magnolia is positioned to navigate the and Jim Stavros. Thank you for joining us. since our inception and continue to provide us with a strong foundation for the long term. Our business model, predicated on low financial leverage, is designed to withstand periods of weak product prices. We exited the quarter with $146 million of cash in our balance sheet, $450 million of undrawn revolver, and $400 million of debt that does not mature until 2026. Our targeted annual capital spending for drilling and completing wells remains at 60% of our adjusted EBITDAX, and we generated $23 million of free cash flow during the first quarter. We remain focused on the things that are in our control. Most of our current planned capital spending and activity for the year occurred in the first quarter. The current weak product prices do not justify bringing new wells online. As a result, our capital spending is expected to see a sharp decline for the remainder of the year. We currently plan to drill a few additional wells in Giddings Thank you for joining us. including any additional savings from our capital program expect to realize at least $55 million improvement in our 2020 cash operating costs in G&A compared with our original plan. A portion of these savings should be realized in the second quarter and more fully captured in the second half of the year. Our cost reduction initiatives will remain an ongoing effort throughout the remainder of the year. As a company, we run a focused business. as a result, narrow focus business, really. And as a result, we can optimize our production on each well. Sometimes that's an advantage, sometimes not. But right now, this allows us, this focus allows us on generating free cash flow at very low product price, in a very low product price environment, and allows us to manage our business more effectively. We can share products and John Stavros. Thank you. and Tom Stavros. Thank you very much. Two of these wells were drilled from the same pad to replicate early stage development. These two wells had 90-day average rates of 1,000 barrels of oil a day. The cost of these wells were more than 20% lower than the 2019 average cost in Giddings, despite having lateral lengths that were approximately 25% longer. Our recent positive results in Giddings increased our confidence on the future development opportunity of the field. with the potential for several hundred drilling locations. Giddings would be the first area where we would bring back a rig and complete wells as product prices recover. We continue to evaluate several small to mid-sized bolt-on and oil and gas property acquisitions opportunities. While the M&A market has been stagnant so far this year due to the weakness in volatility in product prices, there are some signs the process is beginning to loosen. We expect opportunities to expand. Our business will appear later this year once market conditions clarify. As always, we will ensure that anything that is done is accretive to our business and is clearly positive for our shareholders. To summarize, Magnolia's financial position remains strong and the balance sheet provides us with a competitive advantage. Our current cash balance would allow us to fund all remaining capital spending for this year, as well as our cash overhead and our interest payments, at least the remainder of 2020 before considering any revenue generated by our production. Our free cash flow generating business model continues to provide us optionality to allocate capital towards opportunities that are most beneficial to our shareholders. I'd now like to turn the call over to Chris Stavros.

Thank you, Steve, and good morning, everyone. As Steve mentioned, I plan to review some high-level points from the first quarter. to speak to some more detail around our cost savings initiatives and provide some guidance for the second quarter before turning it over for questions. Looking at our quarterly cash flow summary on slide five of the conference call presentation posted on our website, we generated $135 million of cash flow from operations and our total cash outlays associated with drilling and completing wells was $94 million during the quarter. Free cash flow after changes in working Thank you for joining us. and we ended the first quarter with $146 million of cash on the dollar sheet. Reiterating Steve's comment regarding our cash position, we currently have sufficient cash on hand to fund our remaining planned capital expenditures, cash overhead and interest at least through the remainder of the year and carry us into 2021 before consideration of the revenue generated from our oil and gas production. Turning to costs on slide 6, our total cash operating costs in the first quarter, including G&A, was $9.42 per BOE, a 14% decrease from the prior year period. Our cash operating margins after all cash costs were nearly $20 per BOE during the first quarter. Adjusted EBITDAX was $124 million in the first quarter, with total drilling and completion costs of approximately $101 million, or 81% of EBITDAX, and lower than our guidance. Looking at slide 7 of the presentation, total production from the company averaged 68.4 thousand BOE per day during the first quarter, a 10% increase compared to last year's first quarter and approximately the same as volumes in the fourth quarter of 2019. Oil production represented about 55% of our total volumes during the first quarter. Production exceeded our earlier guidance, and as Steve mentioned, our stronger volumes were due to better-than-expected well-performance from both our Carnes and Giddings Field assets. Our gross long-term debt of $400 million in senior notes remains unchanged in the quarter, and we do not expect to issue any new debt. We have approximately $600 million in liquidity, including an undrawn $450 million credit facility. Our condensed balance sheet and liquidity as of March 31 are shown on Slides 8 and 9. Summarize, Magnolia is financially well-positioned to manage through the current challenging period of weak product prices. As part of our cost reduction initiatives in response to much weaker product prices, we expect to achieve approximately $55 million of savings in our 2020 cash costs compared to our original plan. The improvement in costs are largely comprised of savings from field-level operating expenses, gathering and transportation, general administrative expenses, and contractor Large majority of the savings come from payroll and other people-related costs and equipment optimization in the field. These savings are part of our initial cost reduction efforts, and we expect to see more over time. And this is also separate and apart from the cost reductions we expect to realize from our capital program. While a portion of the cost improvements should be evident in the second quarter, the full benefit of the savings is expected to be realized during the second half of the year. In terms of our drilling and completion costs, as we started the year, we expected our average well costs to decline about 10% compared to 2019. In Giddings, drilling and completion costs on a multi-well pad we drilled have already seen a 20% reduction, despite the wells having lateral lengths that are 25% longer. When we continue our early stage development program at Giddings, we should continue to capture additional Turning to some additional guidance, we continue to target our capital spending for drilling completions and related production equipment to be approximately 60% of our adjusted EBITDAX. This is a core characteristic of our business model, which remains unchanged. We released our Carnes operated rig in April and are currently operating one rig at our getting sealed asset. We've ceased all well completion activity for the time being due to very weak product prices, and expect to have several more drilled and uncompleted wells by the end of the year compared to our original plan. This reduction in activity will be reflected in much lower capital with our total spending for the year below our outlays during the first quarter. We currently expect that our full year 2020 capital will be less than half of last year's spending level. Magnolia operates approximately 75% of its total production volumes. We currently expect to shut in less than 5% of our operated production during the month of May and a smaller amount for June as a result of very weak product prices. This includes a mix of operated production in both Carnes and Giddings. Due to these curtailments, we currently expect our total second quarter production to be in the range of 62,000 to 65,000 DOE per day. We estimate our oil production to be approximately 52,000 to 52,000. Looking at our second quarter expenses, unit cash operating costs, including G&A, are expected to decline about 5% from first quarter levels as a direct result of the cost reduction initiatives we have implemented. Finally, as we disclosed in our press release, we incurred a $1.9 billion non-cash pre-tax asset impairment due to significant weakness in product prices. As a result of the impairment, we estimate our G&D rate should decline to approximately $9 per BOE for the remainder of the year. In summary, Magnolia is properly positioned to endure the current downturn in product prices. Our significant cash balance should help us withstand the intermediate term volatility, allowing us to take advantage of potential attractive opportunities to further strengthen the company. We're now ready to take your questions.

We will now begin the question and answer session. To ask a question, you need to press star then 1 on your touch-tone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw it, please press star then 2. At this time, we will pause momentarily to assemble our roster. Today's first question comes from Leo Mariano with KeyBank. Please proceed.

Hey, guys. Just wanted to follow up a little bit on activity levels here. Just in terms of the rig and gettings, I'm not sure if that's still contracted through a certain time. And then I guess if prices stay low, maybe that rolls off. So I was hoping you could address that. And I also wanted to see what type of oil prices you guys might need to start Tracking Wells, again, you mentioned there's a possibility in the fourth quarter, so what would you kind of see for that to happen?

So I think we'd start with the rig. The rig's under contract, but we've made arrangements with the contractor so we can extend that period, and when we come back next year or whatever, we can do that. But I think we're – it's so cheap to drill. and it isn't that much money. Completion is a different story but too so deep to drill. We decided to go ahead and drill and this is a three well pad that we're drilling. So these are pad drilling that we'll bring on maybe in the fourth quarter but probably next year. I don't really know what the price that we'd go back in. The margins are so wide on these wells once they're up and running. You know, you could do almost anything as long as the completion costs were reasonable. So I'm going to guess somewhere in the 30s, whether it's 30 or 35 or some other number, I don't know, but somewhere in that area we'd start completing wells. But, you know, probably not. and the economy is headed. So, you know, somewhere in that area. We should be, you know, if you take our operating costs that Chris talked about and G&A and all that other stuff and take the $9 DD&A rate, you know, somewhere in that 30s, we'll start to report earnings. So, you know, since I'm sort of an old-fashioned investor, that's sort of what I'm looking for.

Okay, that's very helpful for sure. And I guess just in terms of the recent drilling at Giddings, it certainly looks like that 2-well pad was a rousing success. You guys mentioned potential for several hundred locations. Just wanted to dive into that a little bit more. Do you guys feel like that the drilling program at this point has identified some key sweet spots throughout Giddings that can be the target of future pad development here and Do you think that several hundred locations is a pretty high probability at this point in time? What can you tell us about the progress there?

Sample size is 20-some wells. We've experimented with different areas. In this one area, I think we have pretty high confidence. The other areas, we've had some good results, but not many wells. I think the pad drilling will work. in this good area. I don't really know how many locations there are. Given the current pace of drilling, the locations will significantly outlast me. I'm not really concerned about counting up locations, but we should have a very profitable business. Remember, they produce a lot of oil, a lot of product over their lives. If the costs which I think we can get down to around $6 million a well and 50% more saving a Carnes well with more than twice as much production, maybe three times the production with a lower decline. We'll continue working on Carnes, of course, but I think this will provide a ballast to the business. And if you don't know about product prices, you go for these longer live things, where the money, you know, you might not get the best price today, but if you have confidence over two or three years, you'll do a lot better in the Giddings Wells than you will in the Carnes Wells. Carnes Wells, as we look at it, you know, product prices are high. You can drill a hell of a lot of Carnes because you've got real short paybacks, but in the Giddings is for the longer play where you're less confident about oil price. I guess that's how I'm thinking about it at least today.

I think that makes a lot of sense. And just lastly on M&A, you sort of talked about that potentially starting to maybe loosen up a little bit here. You had the one deal in the first quarter. I'm assuming that was kind of a legacy deal negotiated towards the end of the year that sort of closed here. Maybe just talk more about what you're seeing on the M&A side and just kind of how you prioritize free cash flow from here on out.

Well, you know, everything's got to compete with Giddings or cards. So if the money is better spent completing Giddings or Carneswells, that's where the money will go. There's really nothing much to buy in Giddings, so there's really nothing there of great interest. And we have so much, there might be a few hundred acres here and there, but fundamentally nothing very large there. And most of the stuff isn't really in a different part of the basin that might be available. You know, not all that interesting. You know, maybe we'd pay, you know, one or two times cash flow at $30 oil or some, you know, exorbitant price like that. So, if you go to Carnes, there's always small pieces around. And as some of these private equity things unwind, we might find some there. But, you know, we're not going to be big payers there because, you know, Right now, we've got a pretty long runway. I don't view that in this environment or environment I perceive for the next couple of years, drilling locations are going to be rare and special. I think there's a lot of locations around, and I'm not really concerned about locations right now. I'm concerned about cash flow generation.

Okay, great. Thank you.

Thanks. The next question comes from Jeff Grimp with Northland. Please proceed.

Good morning, guys. Steve, I thought your comment on maybe gas making some sense and getting to get after was interesting, so let's open the dive into that more. Can you give us a sense? I'm sure the gas price has to make sense relative to the oil opportunities you have, so there's a little bit more variability in that. and Tom Stavros.

because they also produce some liquids. They aren't dry gas wells. They've got about 20% liquids. So NGL prices, which are in a toilet right now, and it produces some oil. So it's a little, it's got some of that to it. But I think it's probably closer to $3 than $2. We could drill a Giddings oil well Even at $30, easier and more attractively than gas wells, but we could grow a lot of gas wells, high-volume gas wells.

If we wanted to inflate our VOEs, that would be the way. All right. Understood. And on the cost cuts at Giddings, the 20% number that you guys referenced, Can you kind of maybe split that out in terms of maybe some efficiencies that you're seeing from doing pad development that's driving that versus maybe just generic kind of oilfield service company type of cost?

It's not driven by oilfield service guys. You get a little better crews now than you had before because they've weeded out some of their crews. But it's driven by the fact the wells are drilling faster because we know more about it. I think we'll be down another 10% or so at some point here. once we start completing the wells. So I think we're really in the early days of this. But again, it's driven by knowing, having a better feel for what you're doing than we did maybe a year ago.

Got it. Sounds good. I appreciate the time. Thanks.

The next question comes from Will Thompson with Barclays. Please proceed.

Hey, good morning, everyone. Steve, what would cause you to be more proactive about shoving in production? And maybe can you remind us what your marketing arrangements look like and whether you expect any impact from the CMA role? You mentioned reducing GP&T costs and that $65 cash savings. Correct me if I'm wrong, but I believe a lot of the guinea barrels are moving by truck. Just help us understand where the opportunity is.

You know, I sort of take a naive view to Wells. You know, we can't influence the product price by whatever we do. You know, Exxon might be able, or Oxy or somebody might be able to influence the product price. And a lot of them have long transportation, you know, they've got to transport from the Permian to wherever. You know, we basically sell locally. So, you know, Some of the Giddings wells are trucked, but that's in the cost. Ultimately, we'll deal with that. There's a pipeline that we could, oil pipeline that we could acquire. There's one there that we could refurbish, if you want to think of it that way, once we get going again. There's more money there than to speculate on oil prices. Again, I figure I've got a lot of locations. I don't need to do that. I don't really have a way of predicting oil prices. I could prove that to you if I had to. And so I think you just got to run this like a real business, not some wacky oil business. And other people have different objectives. They may have different cost structure. They may have take or pay requirements on the bike. We don't have any of that. We just don't have anything we have to do. We could shut everything in, I suppose. but I don't know what the gain would be in that. The production when it comes back, the period that you're shut in, it's not like putting oil in a tank and then just moving the tank. That recovery has spread over several years. So I just as soon have the cash now and can work with it in this depressed environment. We'll generate free cash. You know, May is going to be ugly for sure. But, you know, we'll survive May and June looks a little better and June will be better. So I'm not really, you know, it's just not the same business model that somebody else might have that might be in five or six basins and, you know, it's got a lot of overhead. This is sort of a simple business. The well generates free cash. We'll run the well. If not, we won't. And we look at that every day on each well. So it's a pretty straightforward calculation. It would be just like running a private business as opposed to trying to optimize something for a public business. I'm not really worried about what the We can make lots more production next year if we need it. But obviously, even if we didn't produce anything, we're probably not going to move the product price.

Okay. And then in terms of gettings, where are you in terms of completion designs, profit intensity, et cetera? Just trying to understand, are you still tinkering with well-designed and I know one challenge in getting well cost down was that you weren't moving to larger pad development just given that you're still in delineation mode. You mentioned $6 million is the opportunity. Does that include moving to larger pad development?

It's what a pad, a small pad would be about $6 million. I don't view that as the ultimate objective. That's just what's are obviously visible now. Once you get there, you move the goalposts. You've got to decide that this business is not an $80 barrel oil business or a $70 business or a $60 business or a $50 business. It's a business that has got to work at much lower prices. It's nice if it goes up. But I think right now there's a lot of demand destruction. It's going to take a while to recover. You know, oil guys are always optimistic that next quarter will be better, maybe a little better. But I don't think you should, you know, you can no longer run your business as if oil is going to be $65 forever. And that means less debt, less interest expense, less overhead, and, you know, and some of your peers are learning the hard way.

Just on the fault, just in terms of completion design, can you just give us a...

There really isn't much change. We've monkeyed with this a lot. I'm sure it'll be tweaked, but right now, you know, We'll get it down to the $6 million run rate, and then we'll look at it again, see if something we can do to take another 10% out. So, you know, right now, you know, if you can produce 1,000 barrel of oil a day, wells, for 90 days or longer, and with a much lower decline than Carnes, completion design is probably okay for now.

Well, thank you.

Thanks. Our next question comes from Neil Dingman with SunTrust. Please proceed.

Morning, all. Steve, just maybe add on to what you were just saying on the Giddings. If you just add a couple more details. I know not long ago you mentioned that you and I were talking. You talked about just on cost, on services, obviously tough business right now. And I'm just wondering for you or Chris and maybe in some of your estimates or forecasts forward, are you – Thank you very much.

or half that. Anyway, I already tried that. I already did that experiment some other place. Anyway, we're not counting on that. I think they're pretty close. Where do you gain, to be honest, in the service companies? what they charge per hour or per day or whatever. It's the quality of the crews. If they recruit their crews at Huntsville, then you're gonna get Huntsville-style outcomes. If these are experienced people who've been around and these are the people they're trying to protect, you're gonna really get good outcomes. It's much more about the quality of the crews than about exactly what they charge. We pay a little more, frankly, for the better crews because all they've got to be is a day and a half better. And they are. The issue with service companies generally is that as the business expands, the crews get lousier and you get worse results and so your costs soar. It isn't that the service companies get rich. There's too much competition, but not that they don't want to be carefree. But I really think that's the key element. We are counting on that the crews stay good quality crews. But as far as actual cost reductions, we're not looking at that. I don't think there's a lot more there, to be honest.

Okay. No, that's a fair point. And then You touched on this, but I'm just kind of curious, your philosophy, you know, in down cycles like this, when you think about shut-ins and, you know, drilling and completion suspensions and, you know, ducts, I'm just wondering, you know, when you put all that together, I mean, Steve, I mean, you know, you always say it doesn't make sense to drill, obviously, in these kind of prices, but I'm just wondering anything else that, I'm just wondering how you, you know, you've shut in a little bit, you've had, obviously, you're going to have much more major DNC suspensions, I'm just wondering if Could you just talk about, kind of, you know, given your past, how you've been... We've only shut in what doesn't make sense.

We're not shutting in to manage production or something. Some other people are clearly managing something else. I don't know what. But, and, you know... We see the run rate. Or we read their press releases. You don't really know what the motivation is. Again, a large company may think it's managing prices, may have some contracts or something. You don't really know what's going on. On the drilling, we had a rig contract. We negotiated with a with a contractor. And so we got pretty cheap prices for drilling some wells. It's where we would drill next anyway. And so we'll drill those wells. As far as completions go, we'll wait until we've got more clarity on product prices. But, you know, I'm guessing that's somewhere in the 30s. And, you know, the rest of... And in Carnes, you know, I assume that the third-party... Operators, the outside operators will pick up at some point there, I guess. So, you know, I don't like building ducts, but we are going to build some. And, you know, mostly because, you know, I got pretty good confidence that oil will get to somewhere in the 30s. You know, if I thought this was stuff that needed 50s, I wouldn't build any ducts.

Thanks. I really appreciate the time. Thanks.

Sure.

The next question comes from Jeffrey Campbell with 2E Brothers. Please proceed.

Good morning. Thanks for taking my question. Steve, regarding the extra giddings locations that were identified in the preamble, I was wondering, does this center mainly on the recent success area, or was this kind of a broader number referring to all the prisons we've done?

No, it's centered on where we recent, not so recent, but where we're doing the development drill.

Okay, great. Thank you. Most every E&P says it's aligning its corporate structure to the current reality, but Magnolia seems to have used more of a scalpel than a machete compared to some peers. Is G&A largely where you want it currently, and how far out into the future are you looking to make these judgments?

G&A is not where we want it to be. It needs to be reduced sharply. So, you know, we're working on a plan to reduce it materially from here. Okay. We might remember that we have a contract with Intervest for some of the back office and some of the well management and that sort of thing. and so that might be a target for reduction.

Thanks. And that actually kind of leads to my last question which is is there any sense when you're at the point in the future when you can expand your Giddings program again that you might develop an in-house capability for those assets or are you likely to keep using something like the current operating arrangement?

No. We'll use our own. We could do that now.

Okay. Thank you.

The next question comes from Biju Perintero with Susquehanna. Please proceed.

Good morning, all. Thanks for taking my question. Thinking about, you know, when you were assuming activities, how we should think about the cons area not necessarily looking for a price, but when you go back to work, should I think about the first couple of weeks going to Giddings and only then going to picking up activities and cars?

Something like that. The first rig and the first completion crew will go to Giddings. We're probably and a couple of other people. So, it's a similar time because we have some ducks there. As far as drilling, I would think the next drilling would be in Giddings. I just don't know. If oil is $35, it would probably be Giddings. If oil is $45, we'd probably put a rig into Carnes. You know, it just depends on how certain I am over time about the direction of prices. You know, if you've got a high degree, if you think it's still volatile, volatile meaning bad volatile, not up volatile, then you probably would spend more in Giddings and less in Carnes. You know, if you thought it was... If you had a spike in prices, we might drill a lot of cartons as well. The payout's real quick. You produce 4,000 barrel a day wells or something like that. You get your money back real quick. Then you've got a long, low-cost stream after that.

That's very helpful. And my follow-up was on the gas optionality you talked about. Are those wells much deeper? Is there an appreciable difference in well cost than you expect for the gas wells?

They're somewhat more expensive. But, of course, we haven't drilled one, and we're not using some of the stuff we've learned since, so I don't really know what it would run us. if they're somewhat more expensive. I'm going to guess it's a $7 million well or $8 million well, but not a $10 million well. But that's just a guess.

That's helpful. Thank you.

Our next question comes from Kashi Harrison with Simmons Energy. Please proceed.

Good morning, all, and thanks for taking my questions. So, Chris, maybe one for you. I was wondering how we should think about, you know, just the 2020 exit rate based on your current expectations and, you know, if you have a sense of how much capital or activity you would need to hold that production class at least through 2021.

You know, we just don't know right now. I mean, we... But what is encouraging is, you know, what you're seeing out of Giddings and the decline rate. So it's obviously, it's a more efficient operation, which I think is what's leading us to allocate money there first. So that and, you know, sort of the other gas production that we have has certainly helped the decline rate and the efficiency of the production overall. But I can't speak to an exit rate right now.

We're lucky we can do next month on an XR rate. I figured being able to figure June was a major victory.

All right, fair enough. And then, Steve, maybe one for you. You talked a bit earlier about just needing to adjust the business to whatever price is right in front of you. And so I was just wondering, how we should think about, or maybe it doesn't evolve, but how you think about inventory depth if we are, in fact, in this $35, $40, $40, $45 world for quite a bit of time. How many locations do you lose, or does that getting inventory that you've talked about in the past feel pretty much unchanged? And by even trying economic inventory.

The getting stuff, we've taken care of the risking of that. So that sort of works in this $35 sort of environment. There might be more locations in a $60 environment. Carnes, I think it works in the same general area. We never had a lot of high wells that required $55 or $60, maybe a few marginal wells in Carnes. you know, that were, you know, out of the main, you know, fairway. We just never had a lot of inventory that was sensitive to the product price, you know, reasonable product price changes. So I, you know, that's why we only have a small reduction in our shut-in wells because the wells sort of work. and the rest of the business is inherently more costly. You know, this runs sort of like you would run it if it was your money rather than some third party's money.

That makes sense. That's helpful. And then maybe just a minor housekeeping question for me. I was just, you know, you talked about the lateral length on these giddings as well being I think 20, 25% longer than last year. I was just curious what that lateral length was for these pads and, you know, is that a good idea of how you think about the long-term lateral length of the wells you'd be targeting in Giddings or if, you know, you might get a little bit longer over time?

Six thousand, roughly, is what we're doing now. You know, we were, you know, below five, sort of. Before, you know, as you get long, we don't have a, you know, a lot of times, some places you Thank you. Thanks.

Our next question comes from Brian Downey with Citigroup. Please proceed.

Good morning. Thanks for taking the questions. Chris, Steve mentioned earlier that the industry needs less interest, less debt, obviously no credit facility balances. As you're thinking about capital allocation, Magnolia Senior Notes have recently been trading around 80 to 85 cents on the dollar, at least that's what we see on the screen. something you've considered using cash on hand or credit facility availability to repurchase any of those notes below par? Would there, I guess, would there be any limitations or difficulties if you wanted to do that strategy in the open market? And could that be part of the Magnolia Capital Allocation Suite?

Probably not right now. You know, I talk about limitations. I mean, I'm not sure how much of that you could, how liquid it is or how much of that you could soak up. But probably not enough to make a difference, frankly.

You know, the other part of it is, you know, we've got five more years on maturity. Six, actually. You know, so you've got a while to go here. And, you know, to give up that optionality to, you know, for a very small gain. I just view it, you know, our interest expense, you know, six times 400 is 24 million a year. So if you could buy it all for $0.80, so now you're down to $0.20, you save hardly anything. It just isn't worth it for the fact you don't have to worry about paying it back for a while. A lot of people have pretty wide discounts. Some guys are 60% discount, 70% discount, and large sums. you know, there it sort of starts to make sense. You know, it just doesn't make a lot of sense. And when we look at it, buying a million dollars at $0.15, at $0.85 would be challenging. So, you know, I sort of like the optionality of the debt out there so far.

All right. That's helpful. Thanks for taking it. Thanks.

As a reminder, if you do have a question, please press star then 1. Our next question comes from Irene Haas with Imperial Capital. Please proceed.

Irene Haas Yes. The question I have for you is your crude price realization. Can we have a little color as to, as we go through this year, what the premium would be versus WTI? I assume that you don't probably have any gravity issue. The second question is what Steve said earlier. You said there's lots of demand destruction. It will take time to recover. Steve, can you quantify what is the time that would be required?

You know, the product price, you know, Chris can talk about product price, but the product price is you got the disaster of May, and then, you know, you is looking better in June. You really have a hard time coming up with a product price that you have any confidence in for this quarter. All of a sudden, let's say the price of WTI goes to minus $55, just screws up the whole calculation because it's the average over the month. Anybody who thinks that they know what the answer is, could make a lot more money than this production business, that's for sure. I think there's a lot of demand. There's airline destruction, cars, all that stuff. They say there's 30% demand destruction. I think that's going to take a while to get back to the 100. I know there are other people with different views. and if you actually knew, also you could make some money. All the stuff I get is from watching television. Everybody on television seems to know, but they seem to know a different number. Chris?

Yeah, Irene, on the differentials, generally we've seen a premium on our realizations compared to WTI, but like Steve said, with trying to In the midst of all the volatility right now, you could have a couple of days that just throws it completely out of kilter. But, you know, as this gets to be, you know, again, more normalized over time, I would expect that premium to sort of be there. I just, trying to quantify this is virtually impossible.

Okay, thank you.

Thank you.

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