Edited Transcript of MGY.N earnings conference call or presentation 12-May-20 3:00pm GMT

Magnolia’s strategy and business model has not changed. The quality of our assets and the characteristics of our business model has served us well 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, which 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 of our capital spending, we expect to see a sharp decline for the remainder of the year. We currently plan to drill a few additional wells in Giddings, although we don’t expect to complete any wells until the fourth quarter or until we have some better clarity around product prices. Our spending for drilling and completions expect to be less in aggregate for the remainder of the year than we spent in the first quarter.

We’ve also taken steps to reduce our operating expenses and overhead in order to better align our cost structure with the environment. Corporate-wide salaries have been reduced by 10%. Excluding any additional savings from our capital program, we expect to realize at least $55 million improvement in our 2020 cash operating costs and G&A compared with our original plan. 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 have run a focused business. As a result — narrow focused 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 resources more easily because our business is so narrow.

Our underlying business and assets performed better than expected during the first quarter, driven by strong production results from both our Karnes and Giddings assets. With no significant financial or operational restrictions or obligations, our business model provides us with the flexibility to adjust our activity levels very quickly in response to changes in product prices. For example, some portion of our acreage in Giddings’ capability produced high flow rate in natural gas wells. While we have not focused on this acreage during the last 2 years, we would consider allocating some capital as acreage should gas prices improve later this year. We expect that these wells to be fully competitive with Haynesville wells.

In Giddings, we brought 4 new wells online during the first quarter with an average 60-day oil production rate of 800 barrels a day per well. 2 of these wells were drilled from the same pad to replicate early stage development. These 2 wells have 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 increases our confidence from the future development opportunity in the field with a 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 midsized bolt-on on 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 of process beginning to loosen. We expect opportunities to expand our business will appear later this year once the market conditions clarify. As always, we will ensure that anything is — that is done is accretive to our business and is clearly positive for our shareholders.

Summarized, 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 opportunity that are most beneficial to our shareholders.

I’d like now — I’d now like to turn the call over to Chris Stavros.

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Christopher G. Stavros, Magnolia Oil & Gas Corporation – CFO & Executive VP [4]

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Thank you, Steve. And good morning, everyone. As Steve mentioned, I plan to review some high-level points from the first quarter, speak to some 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 5 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 capital and capital spending was $23 million during the first quarter, and we’ve generated free cash in every quarter since the inception of the company. We repurchased 1 million Magnolia shares for approximately $7 million and closed on a bolt-on acquisition of primarily non-op oil and gas properties in the Karnes area for approximately $70 million. The acquisition closed in the second half of the first quarter and contributed less than 800 BOE per day of production to the quarter. And we ended the first quarter with $146 million of cash on the balance 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 68,400 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 Karnes 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 of 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. Summarized, 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. Improvement in costs are largely comprised of savings from field-level operating expenses, gathering and transportation, general and administrative expenses and contractor fees. 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 cost 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. Continue — when we continue our early-stage development program at Giddings, we should continue to capture additional efficiencies, which would further reduce our overall well costs.

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 Karnes operated rig in April and are currently operating 1 rig at our Giddings Field 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 Karnes 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 BOE per day. We estimate our oil production to be approximately 52% to 54% of our total volumes.

Looking at our second quarter expenses. Unit cash operating costs, including G&A, are expected to decline about 5% from first quarter levels and 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 noncash pretax asset impairment due to significant weakness in product prices. As a result of the impairment, we estimate our DD&A rate should decline approximately — 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 and allowing us to take advantage of potential attractive opportunities to further strengthen the company.

We’re now ready to take your questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Today’s first question comes from Leo Mariano (sic) [Leo Mariani] with KeyBanc.

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Leo Paul Mariani, KeyBanc Capital Markets Inc., Research Division – Analyst [2]

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Just wanted to follow-up a little bit on activity levels here. Just in terms of the rig in Giddings, I’m not sure if that’s still contracted through a certain time. And then I guess just 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 fracking wells again. You mentioned it is a possibility in the fourth quarter. So what would you kind of see for that to happen?

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [3]

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So I think we start with the rig — the rigs under contract, but we’ve made arrangement 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 still so deep to drill. We decided to go ahead and drill, and this is a 3-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 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 start completing wells. But probably not before that and probably not until we had more confidence in where the economy is headed. So somewhere in that area. We should be — if you take our operating costs, as Chris talked about, and G&A and all other stuff and take the $9 DD&A rate, somewhere in that 30s, we’ll start to report earnings. So that — since I’m sort of an old-fashioned investor, that’s sort of what I’m looking for.

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Leo Paul Mariani, KeyBanc Capital Markets Inc., Research Division – Analyst [4]

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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 kind of tell us about the progress there?

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [5]

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Well, sample size is 20-some wells. So — and 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. So I think the pad drilling will work in this good area. And I don’t really know how many locations there are. Given the current pace of drilling, the locations will significantly outlast me. So I’m not really, really concerned about counting up locations. But we should have a very profitable business. Remember, they don’t decline. They produce a lot of oil, a lot of product over their lives. If the costs, which I think we can get down around $6 million a well, that’s 50% more, say, than a Karnes well with more than twice as much production, maybe 3x the production with a lower decline, we’ll continue working on Karnes, of course. But I think this will provide a balance to the business.

And if you don’t know about product prices, you go for these longer live things where the money — you might not get the best price today, but if you have confidence over 2 or 3 years, you’ll do a lot better in the Giddings wells than you will in a Karnes well. Karnes well, as we look at it, product prices are high, you drill a hell lot out of Karnes because you got real short paybacks. And — but the Giddings is for a longer play where you’re less confident about oil price. I guess that’s how I’m thinking about it at least today.

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Leo Paul Mariani, KeyBanc Capital Markets Inc., Research Division – Analyst [6]

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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 1 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.

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [7]

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Well, everything’s got to compete with Giddings or Karnes. So if the money is better spent completing Giddings or Karnes wells, that’s where the money will go. We don’t — there’s really nothing much to buy in Giddings, so there’s really nothing there that will upgrade 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, not all that interesting. Maybe we pay 1 or 2x cash flow at $30 oil, some absorbent in price like that.

So if you go to Karnes, there’s always small pieces around. And as some of these private equity things unwind, we might find some there. But we’re not going to be big payers there because right now, we’ve got a pretty long runway. I don’t view that, in this environment or environment I foresee 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 generating.

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Operator [8]

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The next question comes from Jeff Grampp with Northland.

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Jeffrey Scott Grampp, Northland Capital Markets, Research Division – MD & Senior Research Analyst [9]

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Steve, I thought your comment on maybe gas making some sense in Giddings to get after was interesting. So I was hoping to 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. But ballpark, is there kind of a gas price maybe relative to oil? I don’t know if you look at maybe ’21 strip prices as some observable number. But just trying to, I guess, get a sense of what that inflection point as to where that could be interesting.

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [10]

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The wells have worked now, to be honest. But no, we probably wouldn’t do anything with it until we got closer to $3 for gas. And because they also produce some liquids. They aren’t just — they aren’t dry gas wells. They had about 20% liquids. So NGL prices, which are in the toilet right now and it produces some oil. So it’s a little — cuts some of that to it. But I think it’s probably closer to $3 than $2. And we could drill at Giddings oil well even at $30, easier and more attractively been than gas wells, but we could drill a lot of gas wells, high-volume gas wells. If we wanted to inflate our BOEs, that would be the way.

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Jeffrey Scott Grampp, Northland Capital Markets, Research Division – MD & Senior Research Analyst [11]

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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…

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [12]

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It’s not driven by oilfield service guys. That — you get a little better crews now than you had before because we weeded out some of their crews. But it’s driven by the fact that wells are drilling faster because we know more about it. It’s actually driven by knowledge rather than anything else. We’re drilling the wells faster. We know how to complete it. We’ve gone through an experimental phase, if you want to think of it that way. It’s principally driven by knowing what you’re doing as opposed to trying and guessing what you’re doing and trying to learn. So I think we’ll be down another 10% or so at some point here in — 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 that we did maybe a year ago.

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Operator [13]

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The next question comes from Will Thompson with Barclays.

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William Seabury Thompson, Barclays Bank PLC, Research Division – Research Analyst [14]

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Steve, what would cause you to be more proactive about shutting 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 in that $55 of cash savings. Correct me if I’m wrong, but I believe a lot of the Giddings barrels were moving by truck. Just help us understand where the opportunity is.

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [15]

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I sort of take a naive view to wells. We can’t influence the product price by whatever we do. Exxon might be able or Occi or somebody might be able to influence the product price. And a lot of them have long transportation — they’ve got to transport from the Permian to whatever. We basically sell locally. So some of the Giddings wells are trucked, but that’s in the cost. And ultimately, we’ll deal with that. There’s a pipeline that we could — oil pipeline that we could acquire — it was one there that we could refurbish it, if you want to think of it that way once we get going again. So I’m not — there’s more money there to be had down the road, not right now. But down the road, trucking is easier.

We’re — if the well contributes to free cash in a predictable way, we’re going to produce — we’re not going to shut in for because to speculate on oil price, again, I figure I got a lot of locations, I don’t need to do that. And I don’t really have a way of predicting oil prices. I can prove that to you if I had to. And so I think you just got to — you got to take — you’ve got to run this like a real business, not some wacky oil business. And somebody — other people have different objectives. They may have different cost structure. They may have take-or-pay requirements up in the pipe. 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 doesn’t — it’s not like putting an oil in the tank and then just moving the tank. That recovery is spread over several years. So I just soon have the cash now and can work with it in this depressed environment. We’ll generate free cash. May is going to be ugly, for sure. But we’ll survive May and June looks a little better, then June will be better. So I’m not really — I set up the same business model that somebody else might have that might be 5 or 6 basins, and it’s got a lot of overhead and has made the commitments to ship in different basins. A lot of companies have more complexity than we have.

So this is sort of a simple business. We can generate — wells 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 if — it’s like running a private business as opposed to trying to optimize something for 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.

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William Seabury Thompson, Barclays Bank PLC, Research Division – Research Analyst [16]

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Okay. That’s helpful color. And then in terms of Giddings, where are you in terms of completion designs, proppant intensity, et cetera? Just trying to understand, are you still tinkering with well design? And I know your only challenge in Giddings is that well cost. Giddings well cost’s down was that you were 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?

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [17]

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It’s well pad, a small pad would be about $6 million. Listen, I don’t view that as the ultimate objective. That is just what’s obviously visible now. We — Once you get there, you move the goal post. I mean you got to be able to — you got to decide that you’re going to — that this business is not at $80 a 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. Oil guys are always optimistic that next quarter will better. It may be a little better. But I don’t think you should — 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 tighter control of which — how you spend your money. So you need to spend money on stuff that works in the 30s.

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William Seabury Thompson, Barclays Bank PLC, Research Division – Research Analyst [18]

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Looks like some of your peers are learning the hard way. Just on the follow-up, just on terms of the completion design. Can you just give us a sense on…

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [19]

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

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Operator [20]

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Our next question comes from Neal Dingmann with SunTrust.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division – MD [21]

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Steve, just maybe add on to what you were just saying on the Giddings, if you could just add a couple more details. I know not long ago, you’d mentioned, I think you now 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 the — your estimates or forecast forward, are you anticipating that part of that $6 million cost, that cost continue to fall? Or maybe just talk about what you’re anticipating on the…

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [22]

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We’re not talk — I never feel sorry for service companies. So I won’t be confused in discussion. But I always think they could cut more and to work for less, cut their CEO pay down to mine. So — or half that. Anyway, I already tried that. I already did that experiment in some other place. Anyway, I — we’re not counting on that. I think they’re pretty close. Where you gain, to be honest, in a service company is not what they charge per hour or per day or whatever. It’s the quality of the crews. If you got — if they recruit their crews at Huntsville, then you’re going to get Huntsville-style outcomes. If these are experienced people, who’ve been around and these the people are trying to protect, you’re going to really get good outcomes. And 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 of — all they got to be is 1.5 days barrel, and they are.

So the issue with service companies generally is, as business expands, the crews get lousier and you get worse results, and so your costs are. It isn’t that the service companies get rich because there’s too much competition, but it’s not that they don’t wanted to get rich. 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.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division – MD [23]

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Okay. No, that’s fair. Fair point. And then you touched on this, but I’m just kind of curious, your philosophy in down cycles like this, when you think about shut-ins and drilling and completion suspensions and docks, I’m just wondering, when you put all that together, I mean, Steve, I mean, 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’ve shut in a little bit. You’ve had — obviously, you’re going to have much more major D&C suspensions. I’m just wondering, could you just talk about kind of — given your past, how you view…

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [24]

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We’ve only shut in what doesn’t make sense. We’re not starting in to manage production or something. But some other people are clearly managing something else. I don’t know why. But — and about 1/4 of our production is outside operated. If they don’t actually communicate with us, the reason we know what’s going on is that we see the run rate so — or we read the press releases. So you don’t really know what the motivation is. So — and again, a large company may think it’s managing prices. It 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 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 I’m guessing that somewhere in the 30s and the rest of — and in Karnes, I assume that the third party operators, the outside operators will pick up at some point there by cash. So I don’t like building docks, but we are going to build some. And mostly because I got pretty good confidence that oil will get to somewhere in the 30s. If I thought this was stuff that needed 50s, I wouldn’t build any docks.

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Operator [25]

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The next question comes from Jeffrey Campbell with Tuohy Brothers.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. – Senior Analyst of Exploration & Production and Oil Services [26]

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Steve, regarding the extra Giddings locations that were identified in the [pre-added list], I was wondering, does this center mainly on the recent success area? Or was this kind of a broader number referring to all appraisals done?

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [27]

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No, it’s centered on where we recent — not so recent, but where we’re doing the development drilling.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. – Senior Analyst of Exploration & Production and Oil Services [28]

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Okay, great. And 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?

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [29]

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Yes, the G&A is not where we want it to be. It needs to be reduced sharply. So we’re working on a plan to reduce it materially from here. You might remember that we have a contract with Enervest to — for some of the back office and some of the well management, that sort of thing. And so that might be a target for reduction.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. – Senior Analyst of Exploration & Production and Oil Services [30]

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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?

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [31]

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No. We’ll use our own. It doesn’t — we could do that now.

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Operator [32]

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The next question comes from Biju Perincheril with Susquehanna.

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Biju Z. Perincheril, Susquehanna Financial Group, LLLP, Research Division – Analyst [33]

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Thinking about when you’re all resuming activities, how we should think about the Karnes area? Not necessarily looking for a price, but when you go back to work is, should I think about the first couple of rigs going to Giddings and only then going to picking up activities in Karnes?

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [34]

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Something like that. First rig — and the first completion crew will go to Giddings. We’ll probably put a completion crew in Karnes at similar timing because we have some docks there. As far as drilling, I would think the next drilling would be in Giddings. I don’t — I just don’t know. If oil is $35, there probably would be in Giddings. If oil is $45, we’d probably put our rig into Karnes. Just depends on how certain I handle over time about the direction of prices. If you got a high degree, if you think it’s still volatile, volatile being bad volatile, not off-volatile. Then you probably would — you spend more in Giddings and less in Karnes. If you thought it was — and if you had a spike in prices in a lot of them, we might drill a lot of current wells because the payout is real quick. You produced 4,000 barrel a day wells or something like that, and you get your money back real quick, and then you’ve got a long low-cost stream after that. So it’s a good well. It’s a good well and where you can reap a lot of money upfront, get your money back real quick.

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Biju Z. Perincheril, Susquehanna Financial Group, LLLP, Research Division – Analyst [35]

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That’s very helpful. And my follow-up was on the gas optionality you talked about. Those wells, are those much deeper there an appreciable difference in well cost that you expect for the gas…

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [36]

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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 want to guess, it’s a $7 million well or an $8 million well, but not a $10 million well. But that’s just a guess.

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Operator [37]

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Our next question comes from Kashy Harrison with Simmons Energy.

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Kashy Oladipo Harrison, Simmons & Company International, Research Division – VP and Senior Research Analyst of E&P [38]

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

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Christopher G. Stavros, Magnolia Oil & Gas Corporation – CFO & Executive VP [39]

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We just don’t know right now. I mean we sort of see out into the current period, but beyond that. But what is encouraging is 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 in 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.

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [40]

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We just — we’re lucky we can do next month on an exit rate. So — but I figured being able to figure June was a major victory.

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Kashy Oladipo Harrison, Simmons & Company International, Research Division – VP and Senior Research Analyst of E&P [41]

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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 do you think about inventory depth, if you are — if we are, in fact, in this $35, $40, $45 world for quite a bit of time? How many locations do you lose? Or is that getting inventory that you’ve talked about in the past still pretty much unchanged? And by even sizing the economic inventory?

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [42]

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Yes. The Giddings stuff, we’ve taken care of the risking of that. So we — that sort of works in this $35 sort of environment. It would be — might be more locations at a $60 environment. Karnes, I think it works in the same general area. So we never had a lot of high wells that require $55 or $60, maybe a few marginal mills in Karnes that were out of the main fairway. We just never had a lot of inventory that was sensitive to the product price of reasonable buyer price changes. So that’s why we only have a small reduction in our shut-in wells because the wells start to work, they’re not — if you have a workforce that’s focused in just a narrow area, get a lot of flexibility if somebody in 5 basins just doesn’t have that kind of flexibility, and this business is inherently more costly. This is run sort like you would run it. It was your money rather than some third party’s money.

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Kashy Oladipo Harrison, Simmons & Company International, Research Division – VP and Senior Research Analyst of E&P [43]

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Makes sense. That’s helpful. And then maybe just a minor housekeeping question for me. I was just — you talked about the lateral link on these getting wells being, I think, 20%, 25% longer than last year. I was just curious what that lateral length was for these pads. And 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 might get a little bit longer over time?

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [44]

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6,000 roughly is what we’re doing now. We were below 5,000 sort of before. As you get — we don’t have a — a lot of times in some places, you’re limited by your leases. We don’t have that kind of constraint. So — but we probably wouldn’t experiment. We would experiment in a higher-price environment to see if it worked rather than trying to stretch the model a little bit and run unnecessary risks right now.

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Operator [45]

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Our next question comes from Brian Downey with Citigroup.

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Brian Kevin Downey, Citigroup Inc, Research Division – Director [46]

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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’s senior notes have recently been trading around $0.80 to $0.85 on the dollar, at least that’s what we see on the screen. Is that 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?

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Christopher G. Stavros, Magnolia Oil & Gas Corporation – CFO & Executive VP [47]

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Probably not right now. I talked about limitations. I mean I’m not sure how much of that you could — how liquid it is that you could stock up, but probably not enough to make a difference, frankly.

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [48]

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Yes. The other part of it is it’s got — we’ve got 5 more years of maturity.

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Christopher G. Stavros, Magnolia Oil & Gas Corporation – CFO & Executive VP [49]

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Yes. 6, actually.

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [50]

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So you got a while to go here and give up that optionality to — for a very small gain. Because I just view it, our interest expense, 6 times $400 million is $24 million a year. So if you bought it for — you could buy it all for $0.80 on the dollar. So now you’re down to $20 million, 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. So a lot of people have pretty wide discount. Some guys are 60% discount, 70% discount in large sums. There sort of starts to make sense. If you — it just doesn’t make a lot of sense. And when we look at it, we — buying $1 million at $0.15 — at $0.85 would be challenging. So it — I sort of like the optionality of the debt out there so far.

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Operator [51]

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(Operator Instructions) Our next question comes from Irene Haas with Imperial Capital.

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Irene Oiyin Haas, Imperial Capital, LLC, Research Division – MD & Senior Research Analyst [52]

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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 required — would be required?

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Stephen I. Chazen, Magnolia Oil & Gas Corporation – President, Chairman & CEO [53]

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The product price — Chris can talk about product price, but the product price is, you got the disaster of May and then it’s 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. And so anybody who thinks that they know what the answer is could make a lot more money than this production business. That’s for sure.

So — and I think there’s a lot of demand. There’s airline destruction, cars, all that stuff. They say that’s 30% demand destruction. I think it’s going to take a while to get back to the 100%. I know there are other people with different views. But — and if you actually knew, also you could make some money. But all the stuff I get is from watching television. Everybody on television seems to know, but always seem to know a different number. Chris?

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Christopher G. Stavros, Magnolia Oil & Gas Corporation – CFO & Executive VP [54]

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Yes, Irene, on the differential side, generally, we’ve seen a premium on our realizations compared to WTI. But like Steve said, we’re trying to — in the midst of all the volatility right now, you can have a couple of days that just throws it completely out of kilter. But as this gets to be, again, more normalized over time, I would expect that premium to sort of be there. I just — I’m trying to quantify it, it is virtually impossible.

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Operator [55]

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At this time, we are showing no further questioners in the queue. And this ends our question-and-answer session as well as our conference. Thank you for attending today’s presentation, you may now disconnect.