Good morning and welcome to the Magnolia Oil & Gas Third Quarter 2020 Earnings Release Conference Call. Please note this event is being recorded. I would now like to turn the call over to Brian Corales, Vice President, Investor Relations. Please go ahead.

Thank you, Gary, and good morning, everyone. Welcome to Magnolia Oil & Gas' Third 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 on the conference call slide presentation with the supplemental data on our website. You can download Magnolia's third quarter 2020 earnings press release as well as the conference call slides from the Investor section of the company's website at www.magnoliaoilgas.com. I will now turn the call over to Mr. Steve Chazen.

Thank you, and thank you for joining us today. My comments this morning will begin with an overview of our business model, discussion of our plans and activities for the rest of the year, including an update on our Giddings development. I will conclude with a general outlook for 2021. Chris will review our third quarter results and our financial position. He will also provide additional guidance before taking your questions. Magnolia's business model, which focuses on spending approximately 60% of our EBITDAX on drilling and completing wells and generating meaningful consistent free cash flow while maintaining low levels of debt, remains unchanged. From our inception more than two years ago, this model continues to position us well by providing significant flexibility in how we choose to allocate our free cash flow. Since the beginning of 2019, we have deployed approximately $165 million of cash towards small and mid-sized bolt-on oil and gas property acquisitions, repurchased more than 9 million shares of our stock, while building additional cash on our balance sheet. We ended the third quarter with nearly $150 million of cash, and we expect our cash balance to exceed $200 million by the end of the year. Turning to our operations. After not completing or bringing on any new wells online during the last 8 months, our third quarter total production of approximately 54,000 barrels of oil equivalent per day represents the trough period for production this year. We ended the third quarter with 8 DUCs in Giddings and 10 DUCs in the Karnes area, while running one rig operated in Giddings, which continues to drill development wells. We began completing wells at Giddings late in the third quarter and recently brought on our first 3-well pad. While still early, the wells on the recent Giddings pad are performing better than the average of the initial 14 wells in our core development area that we discussed with you last quarter. Of the 8 wells we plan to bring on during the fourth quarter, we expect 2 wells to be gassier, allowing us to take advantage of the recent increase in natural gas prices. Our total fourth quarter production is expected to grow 7% to 10% sequentially, and production in Giddings is expected to grow by at least 20%, as a result of the 8 DUCs being brought online. As the timing of these wells will be staggered throughout the quarter, the full impact will not be realized until the first quarter of next year. Our optimism around the opportunity at Giddings continues as we experience additional confirmation around well performance and further improvement on well costs. Current average well costs are running about $6.5 million, which is down from $8.5 million during last year. Our operational efficiency improvements in Giddings over the past year have been substantial as we have focused our activity in our initial core area, transitioned to pad development, and improved the quality of our drilling crews. Drilling costs per lateral foot have declined nearly 55%, and completion costs per lateral foot have decreased 50%, resulting in total well costs per lateral foot declining 45% compared to 2019 levels. These include total costs for drilling, completion, and associated facilities at Giddings. We expect to capture further efficiencies as we execute our pad development, with total well costs falling towards $6 million next year. Before turning the call over to Chris, I want to provide some initial thoughts regarding our plan for 2021, putting a general framework for reinvesting our cash in the business and on the return of excess cash to shareholders. Our plan is to continue to spend approximately 60% of our gross cash flow on drilling and completing programs as part of our organic program. We do not expect to alter this plan as it is a key characteristic of our business model and provides discipline within the organization. At current product prices, we plan to run one rig at Giddings in our development area. Our current drill times, improved efficiencies, and lower costs put us on pace to drill approximately 20 wells in Giddings next year. We expect to begin completing the DUCs in the Karnes area in the first half of 2021, and we currently anticipate a modest increase in non-operated Karnes activities throughout the year. This plan is expected to deliver moderate organic growth compared to our fourth quarter 2020 production levels. As I mentioned earlier, we expect our cash balance to exceed $200 million at the end of the year, and it is difficult to imagine that we need to carry much more than this at any given time. Our overall balance sheet strength is important to us. With only $400 million of bonded indebtedness not due until 2026, paying down debt is not likely to add material value to our stock price. We will continue to look for small to mid-sized bolt-on oil and gas property acquisitions with similar characteristics to our existing asset base. Although we cannot be certain these will occur, we anticipate spending a sizable portion of our cash flows after capital and interest expense on acquisitions. Any acquisition would need to be accretive to the value of our stock and prove our full-cycle cost metrics. Our increased confidence in the Giddings asset area makes us less likely to pursue a larger acquisition. Transactions are most likely to be of smaller bolt-on type that could include producing properties or additional interest in our core areas. In the absence of accretive acquisitions, cash would be allocated to share repurchases. Bolt-on acquisitions and buying back our stock will improve our overall and per share metrics and should generate additional stock market value over time. We will continue to evaluate all cash flow allocation options, including dividends, and plan to provide more details around this as we roll out our full 2021 capital plan early next year. I'll now turn the call over to Chris.

Thank you, Steve, and good morning, everyone. As Steve mentioned, I plan to review some high-level points from the third quarter results, review our financial position and provide some guidance before turning it over for questions. Turning to Slide 4. Magnolia returned to profitability during the third quarter generating total adjusted net income of $15.6 million or $0.06 per diluted share. Our adjusted EBITDAX was $76 million in the third quarter with total drilling and completion capital costs of approximately $27 million. D&C capital represented 36% of our adjusted EBITDAX for the quarter and was better than our earlier guidance. We continue to expect our D&C capital spending to be approximately 60% of our full year 2020 adjusted EBITDAX, which is consistent with our strategy and business model. We reported total production of 54,300 barrels of oil equivalent per day, 50% of which was oil. Third quarter volumes were negatively impacted by 2,000 BOE per day due to the delay of several non-operated wells in Karnes until the fourth quarter, as well as some unplanned downtime at a Karnes third-party processing facility. We have not completed any wells since February and did not bring on any new production during the third quarter. Oil prices stabilized during the third quarter after a very volatile and weak second quarter. Our third quarter oil and natural gas price realizations improved by 96% and 17%, respectively, on a sequential basis. As a result of the recent sharp increase in natural gas prices, we took the opportunity to hedge 50,000 MMBTU per day of natural gas production, with just under half of our total daily natural gas volumes using costless collars with a weighted average floor price of $2.31 per MMBTU and a weighted average ceiling price of $3 per MMBTU from September 2020 through August of 2021. The hedge locks in a floor price of $2.31 per MMBTU that is well ahead of the price we realized thus far during 2020 while providing upside on half of our production volumes, should gas prices rise over $3. We view this hedge as more opportunistic and have no plans to hedge any of our oil volumes. Looking at the quarterly cash flow waterfall chart on Slide 5, we began the third quarter with $117 million of cash and generated $69 million of cash flow from operations before changes in working capital. Our D&C capital was $27 million during the quarter. We completed a small bolt-on acquisition in the quarter, most of which was an increase in working interest in our existing acreage. We repurchased 1.2 million shares of our common stock during the third quarter for $7 million, and have 6.8 million shares remaining under the existing repurchase authorization. We generated $46 million of free cash flow and our cash balance grew by $32 million during the period, ending the third quarter at $149 million. At current product prices, we will continue to generate excess free cash flow after our capital outlays through the end of the year. Our $400 million of gross debt is reflected in our senior notes, which do not mature until 2026, and we do not expect to issue any new debt. Magnolia's undrawn $450 million revolving credit facility was reaffirmed by our bank group last month, and our nearly $600 million of total liquidity is more than ample to execute our business plan. Our condensed balance sheet and liquidity as of September 30th are shown on Slides 6 and 7. Turning to guidance for the fourth quarter and shown on Slide 8, our total capital spending for drilling, completion, and facilities is expected to be approximately 55% of our adjusted EBITDAX during the period. We exited the third quarter with 8 DUCs at Giddings, which we plan to complete and bring online during the fourth quarter. These well completions, combined with several non-op wells coming online in Karnes during the quarter, should provide sequential quarterly production growth of 7% to 10%. Production in Giddings should increase by at least 20%, as we bring on several multi-well pads. Two of the eight wells that we plan to bring online during the fourth quarter are expected to be gassier, allowing us to take advantage of higher gas prices. As a result of these gassier wells, our gas production is expected to be a little higher proportionally during the fourth quarter. We plan to continue to operate one rig focused on drilling development wells in the Giddings initial core area. Our oil realizations are expected to be about a $3 per barrel discount to MEH, and around the same as the third quarter and in line with historical levels. We expect our cash balance to exceed $200 million at the end of the year. And as Steve noted, we do not need to build much cash at all beyond this level. Looking into 2021, we plan to invest approximately 60% of our adjusted EBITDAX on drilling and completing wells, consistent with the capital discipline that supported our business model since our inception. At current product prices, Magnolia plans to operate one rig focused on pad drilling in the Giddings initial core area. Based on current drilling times in Giddings, we estimate a one rig program at our current pace could drill approximately 20 wells per year, which should provide moderate volume growth compared to our expected fourth quarter production levels. In summary, Magnolia is financially well-positioned with ample cash and liquidity. Further drilling efficiencies captured in Giddings should allow us to do more with less, providing us with excess cash to return to shareholders.

Our first question comes from Jeff Grampp with Northland.

Wanted to start maybe on Chris' last point doing more with less and what you guys got going on in Giddings in the well cost front. Do you guys think with seemingly good line of sight to get into a $6 million well, can that be sustainable longer term? And even if we do, at some point in time, get service companies clawing back some margins given that you guys probably still have some more efficiencies to gain, is that kind of a good longer-term development well cost or how should we think about continued efficiency gains?

Almost all the gain came from drilling the wells quicker, which isn't a reason to cut costs from the rig company. So I think the 20 wells for the year is also conservative. So we're continuing to improve our time. And so it might even be more than that. So I think we may be able to get it below $6 million. But I think $6 million in almost any price environment that I could currently foresee or hope for is probably about right.

Okay. Great. And just on the results front, I know we're still early days on that recent 3-well pad, but anything you guys can point to as far as why those are doing better? Is it geology or are you tweaking completions and doing optimization on that front or anything you can conclude at this point?

Well, the average was a number of wells drilled over a couple of years or so, maybe two to three years. And so the average was reduced by some of the weaker wells that were drilled at one point or another that were done in a different way. So we expect that we'll be above that average. I mean, you could always drill a bad well, I guess. But we expect we'll be above that average going forward.

The next question is from Neal Dingmann with Truist Securities.

Steve, I have a question for either you or Chris. You've been generating strong free cash flow, and I noticed in the press release you mentioned stock repurchases. With the additional free cash flow, are you planning to build cash reserves? Since you don't have much debt, what do you foresee as the immediate uses of that cash between returning value to shareholders or possibly making acquisitions?

We allocate 60% of our EBITDAX towards drilling, completing wells, and equipping them. We hope to pursue some bolt-on acquisitions in either Giddings or Karnes, although the market is currently quite tight, limiting our immediate options. Our next priority is likely to be reducing the share count. We are also considering a dividend and will provide more information on that next year. Regarding paying down debt, it doesn't seem practical at this point. We have $400 million in debt and $200 million in cash. While I could potentially increase our cash to $400 million, it doesn't seem wise. In theory, we could start addressing the debt next year, but I don't believe that eliminating all debt would significantly benefit shareholders, so I would prefer to allocate the funds elsewhere.

Great details. I have a follow-up. Earlier this year, you were quite intentional about drilling in Giddings and mentioned the quicker payback in Karnes. Assuming we finish the year around 40, and understanding that you don't have complete details for next year, what are your thoughts on continuing with Giddings versus Karnes given the paybacks of both?

The Giddings wells provide a better cash return compared to the Karnes wells. Although the Karnes wells bring back revenue more quickly, which leads to higher internal rates of return, the Giddings wells will accumulate more money for us over time and provide more work in the present. In a low price environment, the Giddings approach is advantageous. For Karnes wells, the drilling yields revenue based on the current oil price, which averages out over the years. Thus, in today's market conditions, Giddings wells are more appealing. We have drilled some Karnes wells and depending on product prices, we may complete them in the first half of the year, with additional wells likely to be drilled next year. The optimal situation for Karnes wells occurs when oil prices are around $50 or $60 and the payback period is approximately six months. The locations are still viable, and our focus now is on enhancing the lower decline results from Giddings with low finding costs, currently around $6. Overall, I believe that the most effective use of our drilling budget at this time would be for the Giddings program.

The next question is from Umang Choudhary with Goldman Sachs.

My first question is about following up on a previous comment. If commodity prices end up being higher and fall in the range of $50 to $60 for oil, how would you allocate the extra cash flows between Karnes and Giddings? The initial results in Giddings look quite promising. Additionally, if commodity prices are indeed higher, do you foresee the possibility of spending less and directing more cash towards acquisitions or share buybacks?

The formula effectively addresses the situation. If EBITDA is $400 million, we allocate $240 million for drilling. If EBITDA rises to $600 million, we would invest $360 million in drilling. The additional funds would primarily be directed to Karnes, where we can achieve higher prices, quicker payback, and favorable economics. However, we won't modify the program beyond utilizing the 60% cap; we won't go to 80% or 90% spending. In the scenario where EBITDA is $600 million, that would yield $240 million after interest, resulting in about $210 million available for shareholder returns, whether through share buybacks or dividends, depending on the circumstances at that time. Essentially, the formula adjusts itself for these factors, within certain limits. I am not sure what I would do if oil reached $100.

That makes sense. And I guess, my next question was on just Giddings area. Understand it's early days, and you still have your development plan ahead of you. I was wondering if you can provide any initial color on 2021 production growth and CapEx outlook for Giddings specifically based on your plans to allocate one rig in that area?

You can expect to have one rig operating for the entire year. We initially planned to use two rigs, but our efficiencies allowed us to accomplish the same work with just one. We might add a second rig mid-year to drill some exploratory wells to identify areas for expansion, but any additional funds would likely go toward drilling in Karnes. I'm not in a hurry to expand the program; it will grow as planned. If you look at the average well performance we reported last quarter, and assume similar results going forward, we can expect impressive growth. For example, we anticipate Giddings will achieve at least a 20% return next quarter, even with partial results. We plan to drill 11 wells this year, with 8 this year and 3 more next year. Over the next few months, we will continue to drill, and you will see that we've previously discussed 14 wells drilled. By the end of the first quarter, we expect to showcase 25 wells. I'm not sure what additional information you require.

The next question is from Zach Parham with JPMorgan.

In the past, you've discussed having some productive gas acreage in Giddings, and you mentioned earlier in the call that two of the eight Giddings wells scheduled to come online in the fourth quarter will be gassier. Given the increase in the 21 strip to nearly $3, is there a possibility of drilling additional gas wells next year? Additionally, could you provide some general comments on this?

That's the experiment. So we're going to see how these wells do. To be candid, every time we say it's going to be gassier, it turns out to be a great oil well. So we'll see if that works that way. But even the gassy wells produce a few hundred barrels of oil a day of black oil. So they're not just dependent on $3 gas. But $3 gas certainly helped. So we have a fair amount of gas-prone acreage that could be developed in the $3 area. And we're proceeding cautiously. Again, the acreage isn't going anywhere. But that's the purpose of drilling the 2 wells, to see what kind of results we'd get. We expect the results to be very strong.

Fair enough. Just a follow-up. On the recent Giddings completions on that 3-well pad, can you give us some detail on how those wells are spaced? And just any color on how you plan to space wells in the development program going forward?

They're currently spaced widely apart because we have unlimited acreage, and we are uncertain about the best approach. Our focus is not on drilling as many wells as possible, but rather on a few strategic ones. Ideally, if I could place one well in the center of Washington County and tap into the entire area, that would be the perfect scenario. The objective is for each well to not only boost production but also contribute additional barrels. If wells are drilled too close together, they can interfere with each other's production, which I believe has been a mistake in the industry recently. In Giddings, we have sufficient acreage that allows us to space wells widely. The productivity of these wells, based on the performance curves, is quite promising. Therefore, there is no strong justification for tight spacing now or in the future. We will assess how these wells perform over the next four to five years and monitor how the production curve behaves. Particularly in a lower oil price environment, it’s crucial to maximize the return on each $6 million investment rather than drilling additional wells just to boost production. We are not facing the same pressures some have regarding coverage ratios with banks, allowing us to approach our development program thoughtfully and minimize unnecessary expenses in drilling.

The next question is from Lee Cooperman with Omega Family Office.

Yes. I don't think I'm saying anything that you don't understand because I think you're very sophisticated. But at the current strip, what would you look at as the net asset value of the company?

I don't know.

Well, you have an opinion, obviously.

I have a view. It's certainly a lot more than $4 or $5.

The reason I asked the question is that the market has been extremely tough on energy companies, implying they have no future. Every dollar spent on drilling is being significantly discounted. If the market is accurate about a bleak future for energy, we should consider not drilling and instead aggressively buy back our stock whenever it's trading at a substantial discount to net asset value. In terms of our discussion about capital allocation, it seems that stock repurchase makes sense only if we are acquiring something that is significantly more valuable than what we are paying. I believe you understand this, and I encourage you to reduce drilling as long as the market continues to undervalue the energy industry.

I agree with you. The purpose is clear since Karnes is a known area. We don't need to prove that it has value.

No, no.

The Giddings area is unique. By investing there, we're operating at under 60% capacity, so we're currently in the process of finalizing the share reduction program. However, this effort is not solely about decreasing the number of shares.

I believe you understand that purchasing stock at an unfavorable price can be detrimental. The average analyst target is $7.60, and currently, we are double that stock price. Some analysts even value it in the double digits. If you believe those projections are accurate, then repurchasing shares would be the best use of our capital.

It is important to keep that $7.60 at this price, if that's the correct figure. The Giddings program is essential to achieve that.

I got you. Well, I have a lot of confidence that you'll figure out. You're smarter than me.

Well, I wouldn't say that.

The next question is from Duncan McIntosh with Johnson Rice.

Steve, I have one more question regarding the recent three-well batch at Giddings. You've mentioned that the performance of these wells is surpassing what you observed in the first batch on the 70,000-acre core. I'm curious if there are any differences, such as in the sub-surface, a different landing zone, or if you modified the completion recipe. Any insights would be appreciated.

We continue to improve the efficiency, and there are some small tweaks. But the fundamental issue is when you compare these wells with the average, there were some earlier less efficient wells, whatever you want to call them, in that average. But as we showed you, every well. So that's the large difference principally, and there are some tweaks to make it better. And we'll see how they perform over the next 3 or 4 months.

The next question is from Steven Dechert with KeyBanc.

Could you provide maybe some more color on what you're currently seeing in the M&A market, just hoping to get a better sense of what we should expect here in the near term as far as an emphasis on...

There's really very little. People are afraid to buy for themselves and that they have unrealistic expectations. Most of the companies' small assets we're looking at already have too much debt against them, and so there is no net value. I think it will be a while before that's an active part of our business.

Okay. Great. And then can you just provide any rough dollar estimate for the 4Q CapEx number? I understand it's 55% of adjusted EBITDA. But just a rough number there would be great.

You need to calculate the EBITDA and then multiply that figure. It's straightforward. The only time we might deviate from that is if I'm unable to keep it close to that range. Generally, it would be around 60, plus or minus 5%. However, the exact amount is uncertain because these are small figures to manage. So you're saying you're accurate for $2 million, and I'm not really that accurate.

This concludes our question-and-answer session. And the conference has also now concluded. Thank you for attending today's presentation. You may now disconnect.