Magnolia Oil & Gas Corporation Class A

Good day and welcome to the Magnolia Oil & Gas second quarter 2020 earnings release and conference call. All participants will be in listen-only mode. Should you need assistance, please signal 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 a touch-tone phone. To withdraw your question, please press star then two. Please note today's event is being recorded. I would now like to turn the conference over to Brian Corales, Vice President of Investor Relations. Please go ahead, sir.

Thank you, Rocco, and good morning, everyone. Welcome to Magnolia Oil & Gas' second 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 meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ, rhetorically, 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 second quarter 2020 earnings press release as well as the conference call slides from the investor section of the company website at www.magnoliaoilgas.com. I will now turn the call over to Mr. Steve Chazen.

Good morning and thank you for joining us today. My comments this morning will focus on our plans for the remainder of the year, including an update on the Giddings Field. Chris will review our second quarter results and financial positions. He will also discuss our cost savings, where we've made some good early progress to better align our cost structure with the current product price environment. He will then provide some additional guidance before we take your questions. Magnolia's business model remains unchanged, and we continue to focus our efforts on generating stock market value over time. The recent downturn has further solidified our strategy of running a focused business, maintaining low financial leverage Thank you very much. and we remain committed to keeping within our 60% rule for the year. In response to the sharp decline in product prices earlier this year, we took action to reduce activity and capital spending by dropping our operated rig in Carnes and curtailing any completion of additional assets, additional wells throughout our assets. Although we have not completed any operated wells since February, we continue to run one operated rig in Giddings Field We are currently drilling a multi-well pad in our early stage development area. Our ultimate level of activity at Giddings the remainder of this year will depend on product prices that would allow us to keep our spending around 60% of our EBITDAX for the year. At current product prices, we plan to start completing some of the ducts in Giddings towards the end of the third quarter. We do not currently plan to complete any of the operated ducts in the Carnes area during the remainder of the year. We believe that the pace of non-op activity in Carnes is currently picking up. In Carnes, we have more locations in ducts, obviously. But because of the high initial production in a Carnes well, basically you're going to get $40 in $2 gas for it. I think there's plenty of time to reap that maybe next year. But in a Giddings well, we'll talk about here in a minute, the bulk of the production is spread over at least six months. So you get a more average oil price. I'd like to spend a few minutes specifically on our Giddings asset. And we would turn your attention to slide four in the conference call presentation. Since Magnolia's inception two years ago, most of our activity in Giddings was focused on gaining a better understanding of our 63,000 plus gross acre position through a steady exploration appraisal program. We would drill a well and move the rig often many miles or sometimes several counties before drilling another of that well. This was not designed with the intention of forming an efficient development program. The REV was focused on an effort towards learning more about our acreage and establishing a model that would increase our rate of success. Through this appraisal, we were able to outline a core area of approximately 70,000 acres where our results have been very good. While there are also other areas that are getting sufficient and have shown very positive results, It is in this core area where we have the most data and well results. We currently have a total of 14 horizontal wells in this core acreage with at least 180 days of production. Results have been very strong with an average well producing 1,374 barrels of oil equivalent a day for 180 days with half the production stream is oil. that another well, the average well, has produced nearly 250,000 barrels of oil equivalent in the first six months, with about half of that being oil. Production history of these well profiles demonstrates they are very different from a typical shale well. The wells have typically reached peak production in the second 30 days and have a shallower production profile than our Carnes wells and produce more oil over the life of the well. Evidence of lower rate of decline can be seen on slide four. as these wells have 30, 90 and 180 day oil rates of 781 barrels a day, 783 barrels a day and 677 barrels a day respectively. Our most recent wells have exceeded these average rates. Our drilling activity this year in Giddings is focused on our early stage development area and all with multi-well pads. Our first multi-well pad that we discussed last quarter had an average well cost of about $7 million. This was well below the $8.5 million average cost of experience last year. Our well cost should continue to decline towards $6 million per well as we see further efficiencies and gain more experience drilling on the acreage. As an example, on our most recent three-well pad that finished drilling in June, Thank you for joining us. as well as to drill additional paths in Giddings and expect to begin completing wells here before the end of the current quarter. Shallower decline rates and lower well costs should improve our capital efficiency as we continue to pursue our development of the Giddings field. The driver in all of our activities is to keep our cash flow Thank you, Steve, and good morning, everyone.

As Steve mentioned, I plan to review some high-level points from the second quarter results, review our financial position, progress we've made on our cash costs and capital, and provide some guidance before turning it over for questions. Clearly, the largest driver of our second quarter financial results was a severe decline in benchmark oil prices as a result of the sharp and swift drop in oil demand. This negative impact on our oil price realizations was especially evident during the month of May, for which a short period of time resulted in much wider than normal basin differentials. The short-term disconnect to benchmark prices seen during the second quarter has now abated, and we estimate our third quarter oil price realizations to be approximately a $3 per barrel discount to MEH, which is in line with historical differentials. Looking at the quarterly cash flows waterfall chart on slide 5, we began the second quarter with $146 million of cash and generated $33 million of cash flow from operations before changes in working capital. Our costs incurred for D&C capital were $28 million during the quarter. Working capital changes, including the changes associated with investing activities, resulted in a cash draw of $34 million, and we ended the quarter with a cash balance of approximately $117 million. Assuming we don't complete any oil and gas property acquisitions and a current product crisis, we expect our cash balance to build back to levels seen at the end of the first quarter. Turning to slide six, we reported total production of 64.1 thousand barrels of oil equivalent per day, 53% of which was oil and toward the higher end of our guidance range. Highlighting our production at Giddings, our oil production of 6.4 thousand barrels per day during the second quarter declined only 1.5% on a sequential basis, even though we did not bring on any new wells during the period. As Steve pointed out, this clearly demonstrates the shallow decline rate of our Giddings development wells and production stream in the field. Our adjusted EBITDAX was $40 million in the second quarter, with total drilling and completion capital costs of approximately $27 million. We were able to keep our D&C spending at 68% of our adjusted EBITDAX during the quarter, despite the headwinds from very weak product prices. Turning to costs in slide 7, the benefit of our cost reduction initiatives was evident in our second quarter results. Our total adjusted cash costs in the second quarter, including interest expense and G&A, or $8.50 for BOE, a 29% decrease from the similar prior year period and an 18% sequential decline from the first quarter. We remain on track to achieve the $55 million of total operating cost savings we outlined last quarter and we think we can exceed this amount through additional reductions in our LOE and G&A costs. As Steve noted, our costs for drilling and completing wells in Giddings continue to improve and we expect our overall well costs to climb towards $6 million per well through further efficiency gains. Including our DD&A rate of $8.71 per VOE for the second quarter, which approximates our finding and development costs, our full cycle costs during the second quarter were $17.21 per VOE as shown on slide seven. Using this cost structure and our current product prices, we expect to generate positive net income and earnings per share during the second half of the year. Our gross long-term debt of $400 million in senior notes, which matured in 2026, remain unchanged in the quarter, and we do not expect to issue any new debt. We have approximately $570 million in liquidity, including an undrawn $450 million credit facility. Our condensed balance sheet and liquidity as of June 30 are shown on slides 8 and 9. Turning to guidance for the third quarter, we continue to target our capital spending for drilling completions and related production equipment to be approximately 60% of our adjusted EBITDAX, which remains a core characteristic of our business model. We are currently drilling a multi-well pad in Giddings with our one operated rig. Once this pad is finished, we will have eight ducts in Giddings and further drilling will be dependent on product prices and our ability to keep our spending within 60% of our EBITDAX. We also have 10 ducts in the Carnes area but did not plan to complete any Carnes operated wells during the remainder of the year. While we did not complete any operated wells during the second quarter, we do expect to begin completing wells in Giddings towards the end of the third quarter and production from these wells will be evident in the fourth quarter. With no wells turned in line during the current quarter, we estimate our third quarter production to be in the range of 55,000 to 58,000 Thank you very much. The current product prices, we expect our DNC capital as a percent of our adjusted EBITDA to decline during the second half of the year and be well below 60%. We expect to generate free cash flow for the remainder of the year with our cash balance continuing to increase towards year end. In summary, Magnolia is financially well positioned with ample cash and liquidity. We are able to manage our activity levels in response to product price fluctuations and allowing us to allocate capital towards attractive opportunities. We're now ready to take your questions.

Thank you. We will now begin the question and answer session. To ask a question, you may press star then one on your touchtone phone. If you're using a speakerphone, we ask that you please pick up your handset before pressing the keys. To enjoy your question, please press start and 2. Today's first question comes from Neil Dingman with Truist Securities. Please go ahead.

Morning, Steve. My question is, thanks for the data on those first 14 Giddings Development Wills. So really, I mean, both my questions on that topic, so maybe I'll just hit them both. And that's the first, could you all speak to your plan to tackle Giddings as you potentially return activity next year, and specifically, would you focus more on the 70,000 development acres or will you start delineating some of the remaining massive position there? And then really just secondly, you talked about in that development area lowering cost and I'm just wondering how quickly or if you can lower the cost, how that development area would compete with Carnes. Thank you.

We'll start with the next year. Our current plan is to take one rig and continue drilling in the 70,000 acre piece. If we can manage it within the 60%, maybe we'll take a half a rig next year and use that to exploit some of the other places. It's all driven. The model drives off of how much cash flow you have. Oil prices were $40, you get one set of drilling activities at $50, you get another. We would also expect that at some point next year we'd complete some of the Carnes wells. We also see that there'll be a pickup in the activity in Carnes from the non-op people, although we don't have any real numbers for that. The costs, you know, the costs will come down, like, for sure. Because, you know, our days drilling, days to drill a well have declined sharply in the last few months, and we're getting really good progress at that. It comes from drilling in the same area, and you don't have to be quite as cautious as you were in, you know, someplace three counties away. So I'm pretty confident in the declining well costs. The Carneswells are shaped differently. You get a whole bunch of the production very quickly, and then you have a long period of modest production. The Carneswells, you can see them, they all look sort of like this. You have pretty flat production. You start getting declines maybe three months afterwards. The decline is much shallower. and the ultimate recoverable barrels will be significantly higher than a Carnes well. You get your money back quicker in a Carnes well, but you get more barrels. And if you're in a low-price oil environment and you think it's going to get better over time, you want to stretch your barrels over time rather than sort of produce them all at once. It's not a particularly, you know, if you start with a 60% and you say you're not going to, you know, except for our inability to manage exactly, you're not going to exceed that and that's what guides the business. You know, it actually creates the outcome. You know, in a $100 oil environment or $80 environment, we'd probably switch to all-carns drilling. I'm exaggerating the number slightly, but So because you want to reap that $80 or whatever it is as quick as you can, get your money back real quick. In a low-price environment, you want to stretch the production over time. As far as cost goes, they'll come down pretty nicely. They're already really down.

Great details. Thanks, Steve.

And the next question today comes from Jeff Gramp with Northland Capital Markets. Please go ahead.

Good morning, guys. I wanted to continue digging in on Giddings. And Steve, I guess just kind of curious, I know that the 70,000 acres, you got 14 wells on it. Would you say that's all, you know, a decent degree de-risked at this point based on kind of the dispersion of those 14 wells? And then just kind of curious how much variability around that average you're seeing within those 14 wells?

The answer is, I think they're not all bunched in one place, if that's the question. So I think it pretty much tells us what's going on in the 70,000 acres. There's some variability. Most of the variability you might see in the results, you might have a mechanical problem or something like that, especially some of the earlier wells. where we had some mechanical problems and so you'll see more variation than probably exists. There's some variation and there's some, the current wells are, I think we're, as we've got the laterals longer because we have more confidence in our ability not to mess up the well, we're getting better results. So generally speaking, I would view over time that these averages would get better, not worse. It's a lot of locations if you're running one rig. This would be more entertaining if I were 40 rather than 75. Well, good stuff, Bill.

Great, and then on the 2021 commentary that you gave in your prepared remarks, at 40-2, you don't break the rule, you grow production. I guess I just wanted to clarify, is that kind of year-over-year growth, exit-to-exit growth? And then, if I kind of heard you right, Steve, it sounds like that contemplates a Giddings rig, some Carnes-operated ducks, and then some amount of Carnes non-ops. Is that kind of the main inputs there?

Yeah, it'd be fourth quarter over, you know, The growth from the fourth quarter, wherever we exit. So that'll be up from the third quarter. So, you know, that's sort of what we think. So you'll have the non-op in Carnes, completion of the ducks in Carnes, and then one or one and a half rigs in Giddings. at this 42 sort of. Chris showed it in one of the slides. The cash costs are not that great. You're generating a fairly wide cash margin here. More or less, the DD&A rate after the write-down is Pretty much our finding costs. Maybe it's a little high to the finding costs, but it's sort of in that area. So the financial statements, I think, pretty accurately reflect what's going on, at least for a little while. They don't usually over time, but right now they're reflecting pretty accurately what's going on.

Got it. Understood. I appreciate the details and the time, guys.

And our next question today comes from Stephen Decker with KeyBank. Please go ahead.

Hey, just wanted to see if you guys are getting any AFBs from other operators in Carnes.

Not much. You know, we believe that they're doing some, but really not much. I can speculate as to why. But if you looked at it, it may be that they have lease explorations or lease drilling commitments in other basins that they have assets in, which is what I guess is going on.

Got it. Okay, great. Thanks. And that's it for me. Thanks.

Our next question today comes from Greg Tuttle with Simmons Energy. Please go ahead.

Thank you all, and thanks for taking the time. I'm curious as to what is driving the shallow decline in the Giddings field. Is that a function of ESPs, choke management, or just general reservoir quality?

No, it's general reservoir. If you think about a Giddings well compared to, say, a Carnes well, so In Giddings, there are natural fractures, a lot of natural fractures. Historically, the vertical wells were, they used seismic and they drilled looking for the fractures, which provided natural fracking, if you want to think of it that way. So if you drill a horizontal well and you frack it, you'll have the same, some of this Carnes-like effect of just fracturing the reservoir, but you'll also open up some of these natural fractures. And they don't flow real quickly. It takes a while for the oil to move in there. So it's a fundamentally different overall number. You've got some that looks like a typical frac well, but it's nothing to do with... We're not deliberately doing this. This is the way the wells really flow. Gotcha. Gotcha. Perfect.

And then I guess... Maybe there's a question for Chris. With the expectation of a growing cash balance towards the end of the year and then your low cash burdens on a go-forward basis, how should we think about the priority of cash outflows at some point? Is that priority one debt pay down? Is that hitting the A&D market or maybe a mixture of those two and potentially even shareholder returns?

Well, there's only so many things you can do. So, you know, you can buy your shares, you can, you know, pay in the debt or call in some of the debt over time. You know, we've prioritized over the last, you know, certainly a couple of years, we've prioritized acquisitions and we've acquired a bunch of oil and gas properties that have been accreted to the model and accreted to the stock. So, if we can find some of those things, you know, we'd like to do some of those things if they're accretive. and sort of PDP value at best. You know, maybe sort of two, three times cash flow. But otherwise, you know, I'd let Steve talk to the dividend or, you know, something different.

Well, as far as the debt goes, it doesn't make, you know, we only have $400 million in debt. Right. And it's, you know, we've got six more years to go. And, you know, it's not exactly a big burden. And our coverage is... certainly less than one, even in these prices. So there's no reason to do anything with that, and there's no real gain in it, I don't think. Sort of a last resort. I think as far, you know, we'll just see where we are and see what happens with really two things. One is will there be an opportunity in the A&D market to acquire things that fit in? We're not talking about going to some other basin. But things that fit in and give us where there's real synergies. You never really want to buy from somebody that knows more than you do about the asset. So we want to be at least even with them. And there are some small things we can do Thank you guys for the color and I appreciate you taking the time.

Ladies and gentlemen, as a reminder, if you would like to ask a question, please press star, then 1. Today's next question comes from Nicholas Pope with Seaport Global. Please go ahead.

Morning, guys.

Morning.

I just wanted to talk a little bit more, topic of the day, I guess, with Giddings. How many of the wells they are looking at in that core area have, has Magnolia drilled and completed versus what was kind of in place in those numbers upon the acquisition of the asset?

All 14 are ours. Oh, they're all yours? Yeah.

Got it. And when I look at, like, you kind of hit on the variance I think this is a comfort with just a lot of investors with these chalk plays and the variability of kind of performance. I guess you've kind of seen what performance has been to date. Like when you start to project the drilling program in Giddings, what are the magnolia expectations of variance on well performance in that core area going forward?

Well, you know, what we, aside from, you know, a mechanical problem, you know, or, you know, a bad, you know, some kind of drilling screw-up, the wells are, you know, within a modest amount. There are some considerably better, that's true.

Those are the ones that jump out on the screen, I guess, is these huge wells that you guys have done there.

We didn't cherry pick the wells. These are all the wells.

We have 180 days of production. That's all there is. There really isn't anybody else that drills in this area because we have all the acreage. That's all there is. We didn't pick any of it. You want to use the If you want to do a standard deviation, you can do that. But some of the weaker wells are basically ones that had some mechanical problems. They aren't, you know, nothing fundamental. Not to say that they're, you know, if you drill 50 of these, you know, that there won't be some near the edge. You know, as we move, we might try to expand the 70,000 acres to 80,000 or something like that. Thank you. That's all I have. Thanks.

And ladies and gentlemen, this concludes the question and answer session. I'd like to turn the conference back over to the management team for any final remarks.

Thank you for participating in the call, and we'll talk to you next quarter.

Thank you. This concludes today's conference call. We thank you all for attending today's presentation. You may now disconnect your lines and have a wonderful day.