Good day, and welcome to the Magnolia Oil & Gas Second Quarter 2020 Earnings Release and Conference Call. 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 materially from those expressed or implied in these statements. Additional information on risk factors that could cause results to differ is available in the company's annual report on Form 10-K filed with the SEC. A full safe harbor can be found on Slide 2 of the conference call slide presentation with the supplemental data on our website. You can download Magnolia's second quarter 2020 earnings press release as well as the conference call slides from the Investors 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 position. 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 and spending within 60% of our cash flow, allowing us to generate consistent free cash flow. Despite the challenging product price environment during the second quarter, specifically during the month of May, which was quite awful, Magnolia's D&C capital was 60%-68% of our adjusted EBITDAX. Based on our planned level of activity and using current product prices, we would expect our spending to be approximately 50% of EBITDAX during the second half of the year, 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 actions to reduce activity and capital spending by dropping our operated rig in Karnes and curtailing the completion of 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 through 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 wells in Giddings towards the end of the third quarter. We do not currently plan to complete any of the operated wells in the Karnes area during the remainder of the year. We believe that the pace of non-op activity in Karnes is currently picking up. In Karnes, we have more locations in wells. But because of the high initial production in a Karnes well, you're going to get $40 and $2 gas for it. I think there's plenty of time to reap that maybe next year. But regarding Giddings, well, we'll talk about here in a minute. The bulk of the production is spread over at least 6 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 4 in the conference call presentation. Since Magnolia's inception 2 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 and appraisal program. We would drill a well and then move the rig off in many miles or sometimes several counties before drilling another well. This was not designed with the intention of forming an efficient development program, but rather just 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 in our Giddings position that 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 of the production stream being oil. At another well, the average has produced nearly 250,000 barrels of oil equivalent in the first 6 months, with about half of that being oil. The production history of these well profiles demonstrates they are very different from a typical shale well. Wells have typically reached peak production in the second 30 days, and how the shallower production profile than our Karnes wells have produced more oil over the life of the well. Evidence of lower rate of decline can be seen on Slide 4 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, all with multi-well pads. Our first multi-well pad, which we discussed last quarter, had an average well cost of about $7 million. This was well below the $8.5 million average cost that we experienced last year. Our well costs should continue to decline towards $6 million per well as we see further efficiencies and gain more experience drilling on the acreage. For example, on our most recent 3-well pad that finished drilling in June, 2 of the wells achieved company record per-foot drilling costs. Additionally, since we started this early-stage development program, the average lateral well length has increased from about 5,000 feet to between 6,000 and 7,000 feet. Thus, our total well cost with a drop in the average lateral length has increased. The strong well results in this early-stage development, combined with the recent improvement in product prices, has allowed us to drill additional pads in Giddings, and we expect to begin completing wells here before the end of the current quarter. The 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 at around 60% - spending at around 60% of our cash flow. In summary, looking at 2021, if we assume $40 oil and $2 natural gas while maintaining our guidance of 60% of our cash flow, we would have modest growth and generate significant free cash flow. I'll now turn the call over to Chris Stavros.

Thank you, Steve, and good morning, everyone. As Steve mentioned, I planned to review some high-level points from the second quarter results, review our financial position, the progress we've made on cash, cost, 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, where 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 flow's 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 at current product prices, we expect our cash balance to build back to levels seen at the end of the first quarter. Turning to Slide 6, we reported total production of 64.1 million barrels of oil equivalent per day, 53% of which was oil, toward the higher end of our guidance range. Highlighting our production at Giddings, our oil production of 6.4 million 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 on Slide 7, the benefit of our cost reduction initiatives was evident in our second quarter results. Our total adjusted cash cost in the second quarter, including interest expense and G&A, was $8.50 per 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 cost for drilling and completing wells in Giddings continue to improve, and we expect our overall well cost to decline towards $6 million per well through further efficiency gains. Including our DD&A rate of $8.71 per BOE for the second quarter, which approximates our finding and development costs, our full-cycle costs during the second quarter were $17.21 per BOE, as shown on Slide 7. Using this cost structure and 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 mature in 2026, remained unchanged in the quarter, and we do not expect to issue any new debt. We have approximately $570 million of 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 8 wells in Giddings, and further drilling will be dependent on product prices and our ability to keep our spending within our EBITDAX. We also have 10 wells in the Karnes area; however, we do not plan to complete any Karnes operated wells during the remainder of the year. While we did not complete any operated wells during the second quarter, we 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 inline during the current quarter, we estimate our third quarter production to be in the range of 55,000 to 58,000 BOE per day, with oil production in the range of 50% to 52% of our overall volumes. We expect the third quarter to be the trough period for this year in terms of our production. As we begin to bring on wells later this year, we expect our production levels for both the fourth quarter and the 2020 exit rate to exceed our production in the third quarter. At current product prices, we expect our D&C capital as a percentage of our adjusted EBITDAX 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, allowing us to allocate capital towards attractive opportunities. We're now ready to take your questions.

Today's first question comes from Neal Dingmann with Truist Securities.

Steve, my question is - thanks for the data on those first 14 Giddings development wells. So really, I mean, both of my questions are that on 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 Karnes?

We'll start with the next year. Our current plan is to take 1 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 but it's all driven. The model drives off of how much cash flow you have. Oil prices were $40, you get $0.01 of drilling activities; at $50 you get another. We would also expect that at some point next year, we would complete some of the Karnes wells. We also see that there will be a pickup in activity in Karnes from the non-op players, although we don't have any real numbers for that. The costs will come down, for sure, because our base drilling costs have declined sharply in the last few months, and we're making really good progress on that. It comes from drilling in the same area, and you don't have to be quite as cautious as you were in some ways, three counties away. So I'm pretty confident in what declining well costs. The Karnes wells just are shaped differently. You get a whole bunch of the production very quickly, and then you have a long period of modest production. The Karnes well, as you can see, all look sort of like this. You have pretty flat production. You start getting declines maybe 3 months afterwards, but the decline is much shallower. The ultimate recoverable barrels will be significantly higher than the Karnes well. You get your money back quicker in the Karnes well, but you have to 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 until - if you start with the 60%, and you say you're not going to exceed that, that’s what guides the business. It actually creates the outcome. In a $100 oil environment or $80 environment, we probably would switch to all Karnes drilling; I'm exaggerating the number slightly. But because you want to reach that $80 or whatever it is as quickly as you can to get your money back real quick. In a low-price environment, you want to stretch the production over time. First cost goes down, and they will come down pretty nicely; they're already really down.

Our next question today comes from Jeff Grampp with Northland Capital Markets.

I wanted to continue digging in on Giddings. And Steve, I guess just kind of curious, I know the 70,000 acres, you’ve got 14 wells on it. Would you say that's all a decent degree derisked 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?

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 might be due to a mechanical problem or something like that, especially some of the earlier wells where we had some mechanical problems. So you'll see more variation than probably exists. There are some variations, and the current wells are - as we've got the laterals longer, we have more confidence in our ability not to mess up the well. We're getting better results. So generally speaking, I would view that over time, these averages would get better, not worse. So it's a lot of locations if you're running 1 rig. This would be more entertaining if there were 40 rather than 75.

So good stuff though. Great. And then on the 2021 commentary that you gave in your prepared remarks, at $40 and $2, you don't break the rule, you broke production. I guess, 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 Karnes operated wells, and then some amount of Karnes non-operated. Is that kind of the maintenance put there?

Yes. It'd be fourth quarter over - the growth from the fourth quarter, where we were at the exit. So that will be up from the third quarter. So that's sort of what we think. You'll have the non-op in Karnes, completion of the non-operated wells in Karnes, and then 1 or 1.5 rigs in Giddings. At this $42 sort of - there's a pretty - Chris showed it in one of the slides. I mean there’s actually - the cash costs are not that great. I mean, you've got to generate 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 cost, 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 what's pretty accurately what's going on.

And our next question today comes from Steven Dechert with KeyBanc.

Just want to see if you guys are getting any AFDs from other operators in Karnes?

Not much. We believe that they're doing some, but really not much. You - 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.

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

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?

No, that's general reservoir. If you think about a Giddings well compared to, say, a Karnes well. So in Giddings, there are natural fractures, a lot of natural fractures. Historically, the vertical wells used seismic to look for the fractures, which provided natural fracturing, if you want to think of it that way. So if you drill a horizontal well and you fracture it, you'll have some of this Karnes-like effect of just fracturing the reservoir, but you'll also open up some of these natural fractures, and they don't flow really quickly. It takes a while for the oil to move in there. So it's a fundamentally different overall number. You've got some wells that look like a typical frac well, but it's nothing to do with - we're not deliberately causing this. But this is the way the wells really flow.

Got you. Got you. 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 paydown? Is that hitting the acquisition market or maybe a mixture of those two and potentially even shareholder returns?

Well, there are only so many things you can do. So you can buy your shares, you can pay down debt or call some of the debt over time. We prioritized over the last, certainly, a couple of years, acquisitions, and we've acquired a bunch of oil and gas properties that have been accretive to the model and accretive to the stock. So if we can find some of those things, we'd like to do some of those things if they are accretive and have sort of a 2, 3x cash flow. But otherwise, I'd let Steve talk to the dividend or something different.

But as far as the debt goes, it doesn't make sense. We only have $400 million of debt, right? And we’ve got 6 more years to go. And it's not exactly a big burden. 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. I think as far as we’ll just see where we are and see what happens with really two things. One is will there be an opportunity in the acquisition market to acquire things that fit in? We're not going to talk about all into some other basin, but things that fit in and give us where there's real synergies. You never really want to buy from somebody who knows more than you do about the asset. So we want to be at least even with them. So - and there are some small things we can do, like buying increased working interest in our current properties. The second thing is that we have bought stock on occasion, and that's still an option for us right now.

Today's next question comes from Nicholas Pope with Seaport Global.

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

So all 14 are ours.

They're all yours?

Yes.

Got it. And when I look at the - you kind of hit on the variance that we see. And 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 what is - 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, aside from a mechanical problem or some kind of drilling issue, the wells are within a modest amount - there are some considerably better, that's true.

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

These are all the wells that we have 180 days of production. That's all there is. We didn't pick any other wells that were drilled in this area because we have all the acreage. So that's all there is. We didn't select any of it; it is what it is. And so if you want to use standard deviation, you can do that. But some of the weaker wells are basically ones that had some mechanical problems. They are nothing fundamental, not to say that there aren't if you drill 50 of these, that there won't be some near the edge as we move - as we might try to expand the 70,000 acres to 80,000 or something like that. You could run into an edge play, I suppose. But as far as drilling within the sort of current boundaries, this is what you're going to get. You will get some variance. There's no question about that. But we've shown you all the data there is. We don't have anymore.

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.