Good day, and welcome to the Magnolia Oil & Gas First Quarter 2022 Earnings Release and Conference Call. Please note this event is being recorded. I would now like to turn the conference over to Brian Corales. Please go ahead.

Thank you, Matt, and good morning, everyone. Welcome to Magnolia Oil & Gas's First Quarter Earnings Conference Call. Participating in 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 first quarter 2022 earnings press release as well as the conference call slides from the Investors section of the company's website at www.magnoliaoilgas.com. I will now turn the call over to Mr. Steve Chazen.

Thank you, Brian. Good morning, and thank you for joining us today. We continue to execute on our strategy and business model, which limits our spending to 55% of our EBITDAX on drilling and completing wells. This is expected to deliver mid-single-digit annual production growth along with high full-cycle operating margins. The remaining 45% will be allocated towards a mix of accretive bolt-on acquisitions, dividends, and share repurchases. During the first quarter of 2022, we grew our total production 15% year-over-year and 3.5% sequentially, while spending just 28% of our EBITDAX on drilling and completing wells, generating operating income margins or EBIT of 62%. Quarterly production was at the high end of our guidance, mainly due to better performance at our Giddings asset. Total production at Giddings grew 24%, and oil production grew 31% compared to the same period last year. Our free cash flow in the first quarter was approximately $200 million, and we distributed nearly all of it to our investors through share repurchases and dividends. We repurchased a total of 6 million shares during the first quarter, reducing our total diluted share outstanding by 9% compared to last year's first quarter. We also paid the second installment of our semiannual dividend of $0.20 a share, which is based on our full-year 2021 results recast at $55 oil, bringing the total dividend associated with 2021 results to $0.28 per share. Despite the significant return of cash to our shareholders, we ended the quarter with $346 million of cash on our balance sheet, roughly unchanged during the quarter. Together with our 15% production growth, a 9% decrease in our total diluted share count, our year-over-year production per share growth was 27%. The combination of continued moderate growth and share reduction provides greater capacity for dividend growth over time. We continue to operate 2 drilling rigs and expect to maintain this level of activity for the balance of the year. Efficiencies such as faster drill times, longer laterals, and more wells per pad are expected to lead to more net wells during the year, leading to approximately $25 million of additional capital. We expect to see another $25 million of spending resulting from increased oil service cost inflation for both material and labor. The longer laterals and shorter cycle times are expected to benefit our production volumes during the remainder of 2022 and into early next year. As a result, we now expect our full year 2022 production growth to exceed 10% compared to our previous forecast of high single-digit growth. Our operating team continues to make strong progress, steadily advancing the development of our Giddings asset, and we've been successful in offsetting some of the oilfield cost inflation through ongoing efficiency gains. We have improved our drilling feet per day by about 20% compared to a year ago and increased the lateral length of the average Giddings well by about 15% to 8,000 feet, with some wells expected to surpass 10,000 feet. With Giddings still in relatively early stages of development, our operating team's improved understanding and growing experience will allow us to increase the oil and gas recoverability from the asset to the application of modern completion techniques and to further fuel field efficiencies. Giddings now makes up nearly 60% of our total company production compared to one-third of our volumes in 2019. Magnolia remains very well-positioned in the current environment. We believe that reinvesting in our business to achieve moderate, predictable annual volume growth is important for a company of our size while balancing this with a meaningful amount of cash returned to our shareholders. Our gradual and measured approach to both the appraisal and development of Giddings Field has created operating efficiencies leading to some additional net wells and higher growth this year. At current product prices, we expect our capital for drilling and completing wells to be less than one-third of our cash flow, well below our 55% spending cap and resulting in significant free cash flow. The absence of hedges on our production allows for strong product price realizations. Most of the free cash flow is expected to be allocated towards improving the per-share value of the company, including our plan to repurchase at least 1% of our outstanding shares each quarter. We also expect our dividend to grow at least 10% annually as a result of production growth, combined with a steady reduction of our share count. I'll now turn the call over to Chris.

Thanks, Steve, and good morning, everyone. I plan to review some items from our first quarter and refer to the presentation slides found on our website. I'll also provide some additional guidance for the second quarter and the remainder of the year before turning it over for questions. Beginning with Slide 4, which shows the summary of our first quarter. Magnolia continued to execute on our business model, building on last year's accomplishments as demonstrated by our very strong first quarter 2022 financial and operating results. We established corporate records for many of our key financial metrics during the first quarter, including net income, diluted earnings per share, free cash flow, and most notably, operating income margins or EBIT of 62%. These results were supported by the absence of hedges on our production, providing strong product price realizations, our efforts around cost containment, and continued moderate production growth. We generated total net income for the quarter of $209 million, including an effective tax rate of 8%, which was at the high end of our guidance and due to stronger product prices. Using our total diluted shares outstanding, including both Class A and Class B common stock, it is calculated to $0.92 per diluted share for the first quarter. Our adjusted EBITDAX was $298 million in the first quarter. Total D&C capital of $83 million was lower than our earlier guidance, representing just 28% of our EBITDAX. Overall, company production volumes grew 3.5% sequentially and 15% year-over-year to 71,800 barrels of oil equivalent per day in the first quarter. Looking at the quarterly cash flow waterfall chart on Slide 5. We started the year with $367 million of cash. Cash flow from operations before changes in working capital was $268 million during the period with working capital changes and other small items impacting cash by $28 million. Our D&C capital spending, including land acquisitions, was $84 million. As Steve mentioned, we returned the majority of our free cash flow to our shareholders during the first quarter. Most of this cash return was in the form of share repurchases, where we spent $130 million buying in 6 million shares. Cash allocated to repurchasing our shares during the first quarter was more than 50% greater than our capital outlays for drilling and completing wells. Looking at Slide 6, this illustrates the progress of our share reduction since we began repurchasing shares in late 2019. Since that time, we have reduced our total diluted share count by nearly 43 million shares, or approximately 17%. Magnolia's weighted average fully diluted share count declined by 3.6 million shares sequentially, averaging 227.4 million shares during the quarter. We currently have 14.3 million shares remaining under our current repurchase authorization, which is specifically directed towards repurchasing shares in the open market. As shown on Slide 7, we also used $49 million of cash, or $0.20 a share, to pay our final semiannual dividend associated with our full year 2021 results, recast using oil prices of $55. Inclusive of the interim dividend paid in the third quarter of last year, the total dividend associated with our 2021 results was $0.28 per share. We expect our dividend to grow at least 10% annually based on the continued successful execution of our strategy. Our philosophy is to continue to maintain low leverage and a strong balance sheet. We have approximately zero net debt and expect to generate a significant amount of free cash flow throughout the year. Our $400 million of gross debt is reflected in our senior notes, which are callable later this year and do not mature until 2026. Including our first quarter ending cash balance of $346 million and our undrawn $450 million revolving credit facility, our total liquidity is approximately $800 million. Our condensed balance sheet liquidity as of March 31 can be found on Slides 8 and 9. Turning to Slide 10 and looking at our per-unit cash costs and operating income margins. Despite the substantial increase in product prices over the past year, we've seen only a small increase in our total costs. Our total adjusted cash operating costs, including G&A, were $13.18 per BOE in the first quarter of 2022, an increase of $2.45 per BOE compared to year ago levels, and our revenue per BOE rose by more than $21 per barrel over the same period. Including our DD&A rate of $8.21 per BOE, which is generally in line with our F&D costs, our operating income margin for the first quarter was $36.48 per BOE or 62% of our total revenue. Simply put, we captured 88% of the revenue increase in our operating income margin on a year-over-year basis. Looking at a few specific cost items, our overall lease operating expenses increased compared to the prior year, mainly due to higher workover-related activity and some general labor and materials inflation. The workover activity, which can vary from period to period has already started to have a positive influence on our production. The increase in GT&T expense is largely a result of much higher natural gas and NGL prices. As prices move higher, the GT&T expense would also move higher and vice versa. Finally, G&A expenses declined on a year-over-year basis as a result of savings realized from last year's termination of the EnerVest operating services agreement and partly offset by some additional personnel costs associated with our growth. Looking at our total cost structure, we would expect the remainder of the year to be similar to first quarter levels on a per BOE basis. Turning to some guidance for the second quarter and our view for the remainder of 2022. We are currently operating 2 drilling rigs and plan to continue at this level of activity through the end of the year. One rig will continue to drill multi-well development pads on our Giddings asset. The second rig will drill a mix of wells in both the Karnes and Giddings areas, including some appraisal wells in Giddings. We continue to improve our efficiencies in the Giddings Field, which should help to offset some of the oil field cost inflation and will also lead to some additional net wells this year. Our total capital is now estimated to be approximately $400 million for this year, which represents an increase of $50 million from our earlier expectations. As Steve discussed, about half of this increase is a direct result of drilling faster and drilling longer laterals leading to more net wells for the year. The other portion of the increase is due to oil field service cost inflation for both materials and labor. Despite the modest increase in capital for this year, we still expect our spending to be less than it was during 2019. This was during a period when we were also operating 2 rigs when our production was more than 10% lower than current levels and when oil prices were around $60 and natural gas was under $3. Our cost per lateral foot for drilling and completing wells this year is expected to be about half the level when compared to 2019. As a result of the additional efficiency-driven net wells, we now expect our full-year 2022 production growth to exceed 10% compared with our earlier guidance of high single-digit growth. Production growth at Giddings this year should be around 25%. Looking at the second quarter of 2022, we expect total production to be between 72,000 and 74,000 BOE per day. Most of the wells are scheduled to be turned on in the latter part of the second quarter, which is expected to benefit production growth during the back half of the year. Our D&C capital is estimated to be between $100 million and $110 million for the second quarter and is expected to be in this range for the remainder of the year, consistent with the $50 million increase I described earlier. Should product prices remain at their current elevated levels, we would expect our second quarter effective tax rate to be between 8% and 10%. As I mentioned earlier, we remain completely unhedged for both oil and gas production, allowing us to fully capture higher product prices. Oil price differentials are anticipated to be approximately a $3 per barrel discount to MEH and in line with recent quarters. Our fully diluted share count for the second quarter is estimated to be approximately 223 million shares, which is 8% below year-ago levels. We're now ready to take your questions.

Our first question will come from Neal Dingmann with Truist.

My first question is on capital allocation, specifically, it's pretty amazing that you all were able to continue to spend about 50% more on shareholder returns than into the drill bit. And I'm just wondering two things here: One, this is largely due to the strong well results you continue to see at Giddings, and you anticipate this proportion of spending on the foreseeable future.

Yes. The Giddings wells are doing very well. And the Giddings program is doing very well. So I think that you have to attribute the ability to spend less and produce more basically is Giddings, although Karnes has done well also. The proportion, I mean, basically, there's only a few items you can spend the excess on. You can spend it on dividends, you can spend it on share reduction, or you can spend it on acquisitions. So we spent essentially all of it on dividends and share reduction. In the second quarter, it's probably going to be similar. We'll probably spend the bulk of it on share reduction so the share price stays reasonable. We're trading at a very low multiple of earnings or cash flow. And so as long as you have this money, you put it in a share reduction because we believe maybe rightly or wrongly, but as we reduce the shares, it basically allows for larger and larger dividend increases because of the way we manage the dividend size as we recast the current year in the $55 oil environment and then figure out how much we can afford to spend on dividends out of that. So if you reduce the share count and as production goes up, the percentage of the growth of the dividend will follow that. So if we bought in 4% of the shares and we grew the production 6% in the current year, then the dividend would go up 10% roughly. Obviously, if we're doing better than that, more share reduction and more volume growth, the dividend will be higher growth could be higher than 10%.

No. I'd love to hear such a great plan. And then secondly, just maybe operationally, specifically a bit more on Giddings if you could. Could you speak broadly as to what the aerial extent of the current delineation program? And then how concentrated is the current development side of that program with those two rigs?

The development program is largely focused in a few areas, likely covering less than 100,000 gross acres. Nonetheless, our understanding of the reservoir has significantly improved over the past year. We have put considerable effort into gaining a deeper insight into the reservoir. While I can't provide specific details, the area is expanding significantly because we have identified effective methods to make certain locations work, using better drilling techniques and avoiding depleted reservoirs that are thick in this region. There are areas that have been depleted by earlier wells, but if we can steer clear of those spots, we can uncover large pockets of oil, and we believe that strategy is proving successful. This essentially increases the area we can explore substantially. While we cannot determine the exact extent, it does broaden our aerial reach considerably. We maintain a five-year drilling program to ensure we have a clear plan. However, this could extend much longer with two rigs. It's an ongoing advantage; as our understanding grows, we expect continued growth over time. We anticipate a growth rate of around 6% in the mid-single digits, which might account for some decline at Karnes. This is likely a conservative estimate.

Our next question will come from Leo Mariani with KeyBanc.

Just wanted to follow up a little bit at Giddings here. You obviously have talked about better well performance there. Will there be any way to like give us kind of a round number of quantification, like, hey, these wells are 20% better than they were last year on productivity? Anything you could share on that would be helpful.

It's around 20%. We can't provide an exact figure because it fluctuates and varies from year to year. We're drilling longer laterals now; a couple of years ago, we were at 4,000 feet, and now we're at 8,000 to 10,000 feet. Our productivity has significantly increased. We're drilling the wells much faster, and the less time spent drilling, the better the outcomes. It's a notable improvement. Additionally, with oil prices at $100, we are consistently seeing better results.

Yes. Okay. Makes sense. And then I guess just based on the answer to kind of your previous question, I know the plan was to drill some step-out appraisal wells here in '22. Should I take it that you've had some incremental success with that here this year as you kind of talked about some of the areas that maybe you didn't think would work? So I just want to make sure I understood that.

Yes, that's correct. We're planning to drill additional wells and are also working on determining the optimal spacing within this program to maximize each well's efficiency. We've dedicated some time to understanding the right spacing, and we're making progress. In summary, the appraisal program is progressing well.

Okay. Very helpful. And I wanted to see if you could maybe quantify a little bit what the kind of rough increase was here in '22 and the number of sort of lateral feet drilled kind of versus the earlier budget. You obviously had referenced clearly being able to build faster on these wells? Is it like a 10% increase in lateral feet or something versus that earlier budget? Just trying to get a ballpark on what that might be.

I don't know our earlier budget. Chris?

Yes. No. I think what we said was we're drilling wells on average that are exceeding 8,000 feet, maybe a little higher than that. And we're continuing to sort of push more to the extent that it makes sense. I mean as Steve said in his remarks, some of the wells that we're drilling will exceed and surpass 10,000 feet. So last year, we were sort of running around 7-ish.

A simple way to look at it is virtually every month, we take the drill part of it. We drill a well at a record short period of time. And so what's happened is we're going to drill more wells with two rigs than we thought we'd be able to drill, even with the longer laterals and all of their stock. What that does is create more completion costs. And so what you're looking at with the $50 million is actually the completion cost of the extra wells that are caused by the quicker drilling time. So I think if you want to think it's an easy way to come up. And so we wind up drilling, completing more net wells than we bought. But we continue to set records virtually every month for how fast we are drilling the well. It's a better understanding of the reservoir so that you can skip over some of the problems that might be in the wellbore.

Our next question will come from Zach Parham with JPMorgan.

I guess first one just on cost inflation. Can you talk a little bit about the drivers of the CapEx increase, particularly the portion driven by inflation? And maybe just give us some color on how contracted you are on some of your key service lines for the rest of the year?

Yes, Chris, why don't you answer that for him.

Well, I mean, first off, we've got everything, all the materials and necessary items to complete our scheduled plan for this year. Really sort of the point is what's not up. I mean sort of everything has moved higher, whether it's mostly focused on your completions and some labor too. It's not so much the sand necessarily, but it's hauling it. And so you try to look at some specific things that you can do, make some arrangements or tricks on moving sand. But look, every item is up and while we baked into the updated numbers is pretty much accommodating for most, if not all of it for this year.

We also continue to contract ahead. So we're not stopping at the end of the year. So as the year progresses, we continue to add to the takeoff so we always have a significant amount of contracted running room ahead.

Got it. Then maybe just a follow-up on cash return. You talked about basing the dividend on the $55 and $2.75 price environment. And given that the strip is trading below the price would do at this time?

We'll probably...

Got it. So you'll consider taking that price up when you lay out the dividend.

Clearly, you take the gas price up. But we base it on that so that we can always pay it. A true dividend investor, I don't mean somebody who just wants to participate in the oil price. So a true dividend investor wants the certainty of getting it, which is caused by your balance sheet and how much you pay out of your earnings and a growth rate that they can count on. And so that's what the base dividend is intended to cover. And it will grow at least 10% a year or maybe more earlier, and who knows what later. But so it's intended to appeal to the person who wants a sure dividend. Beyond that, right now, a sensible strategy is to repurchase the shares. I think there's a significant disconnect between prospects for our industry and the stock price is an opportunity to buy your shares, which really shouldn't be missed. I believe that for this year, the main plan is to focus on share buybacks. After this, if it becomes harder to purchase shares or if the market recognizes the industry's true value, we will look for other ways to return money, such as dividends. Currently, the market seems to think the entire industry will fail in five years. Once we move past that perception and the stock starts reflecting a more accurate valuation, we can consider dividends. My confidence in the product pricing has never been higher, at least for the next few years. I believe that the industry could reevaluate from representing 4% of the S&P to around 10% over time. Therefore, our immediate focus will be on increasing the base dividend as promised and buying back shares while they remain reasonably priced.

Our next question will come from Umang Choudhary with Goldman Sachs.

Early in the year, you had indicated a strong macro environment in the first half. And then you were concerned about a slowdown in the second half. Would love about your updated thoughts on the macro here?

The predictions are always challenging, especially regarding the future, and I don't know anyone with an impressive track record. For the industry, I don't foresee much risk this year. There may be a slight decline in oil prices, but not significant due to the tight market. The situation seems to be that the oil and gas sector has had numerous opportunities but continues to produce too much. This time, the constraints on labor markets and supply chains might help prevent overproduction. In this current environment, even if there was a desire to expand significantly, it's difficult due to a lack of supplies and labor, as well as challenges in drilling. As long as this persists, I expect product prices to remain relatively robust. A serious recession would impact oil and gas prices, similar to other sectors, and raising interest rates may affect the auto, housing, and stock markets. While they believe this will reduce inflation, I remain uncertain. Provided demand stays strong, I don't foresee significant supplies entering the market, and I'm not particularly concerned about Russia, as they seem to be selling oil at discounted rates outside the mainstream markets. Even if sanctions lifted, additional oil supply would likely be minimal, and I don’t think the Saudis plan to inundate the market. Overall, I anticipate solid product prices in the coming years, with natural gas surprisingly competitive with coal. While a recession is possible, it usually stems from lost confidence in monetary policy, and I doubt this next one will stem from any notable changes in that regard.

Yes, I appreciate the color. That's really helpful. And then I guess on your point about higher natural gas prices, I was wondering, I mean, you do have a lot of acreage, which are gassier in your Giddings asset. Any thoughts around pulling that forward from a development cadence perspective? And how does that tie into your thoughts between relative economics between oil drilling in Giddings and gas drilling in Giddings?

Oil is not at a low price in my opinion. I prefer $7 gas or $100 oil, and I've invested in both. This allows us to steer clear of the gassier areas and focus on the oilier ones, giving us more flexibility in our drilling operations. However, adding a rig is not feasible at the moment since there's no reasonably priced rig available that comes with a competent crew. A good crew is essential for success, and currently, if you try to add a rig, you wouldn't find a good crew available. I’m not interested in subpar crews because they lead to significant issues. As a result, we are not distinguishing between oil and gas anymore since the gas projects are performing quite well, particularly in terms of NGL pricing.

Our next question will come from Charles Meade with Johnson Rice.

I just want to say that I appreciate when you share your unfiltered opinions, Steve. I don't think you're aiming for a role as a commentator on CNBC, but they could definitely benefit from your insights.

I was thinking of becoming a security analyst, but the pay isn't very good, so...

No, no, it sure hasn't been especially in this wonderful sector. But actually, I do you have some serious questions about your asset here. First point, on your longer laterals, so it's great that you're extending them from 7,000 to 8,000 feet on average. And I'm curious though, this is for a long time, been one of the best ways to increase your capital efficiency. So I'm wondering what has changed that you're doing this now? Are you going to a new area with just bigger leases and more lateral available to you without work? Or is this instead perhaps something like you're doing more land work ahead of your rigs to put the longer laterals together? What are the drivers there?

We don't encounter the same land issues that others face, like those in Karnes or the Permian, because we own a significant amount of land. As a result, we can effectively navigate the zones that have been depleted by previous wells. The key challenge is figuring out how to drill around these depleted zones without losing circulation as we pass through them. We've figured out how to manage this, which reduces the complications of circulation loss while drilling.

So it's not a land limitation. It's drilling engineering.

Yes, exactly. So with the control, not within the control of some guy who has a ranch and lives in River Oaks.

Okay. For the second question, Steve, could you share your insights based on your extensive experience? You mentioned that acquiring another rig at the current high rate would likely result in having a less experienced crew. Looking ahead to 2023 for Magnolia and the industry, are you worried that while you may maintain your two rigs, your crew could be diminished by having to start new crews elsewhere, potentially leaving you with a largely inexperienced crew? Do you think this situation might occur across the industry, leading to further inflation in 2023?

I am uncertain about inflation. With only two rigs, managing the crew is easier compared to someone who operates 20 or 25 rigs. We can negotiate with the contractor regarding the crew, but for those who manage a larger number, making those kinds of decisions becomes quite challenging. The contractor will use the same experienced workers to train new hires. While I can't comment on inflation specifically, it does impact efficiency. It's not typically done in the usual way, as instead of spending 20 days to drill a well, it now takes 22 days. Right. Not so much inflation, but efficiency could be on the... Yes. We experienced a significant downturn, resulting in many job losses. To attract these workers back to the industry, we will need to offer competitive wages, potentially including layoffs at Amazon to draw some of their truck drivers. Recruiting will involve sourcing talent from community colleges for training on our teams. Although it requires time and effort, it's definitely achievable. We maintain low turnover among our own staff and field workers. The industry offers good pay and benefits, making it a solid career choice. However, we did face a downturn that caused many people to explore other opportunities, some of which may have been temporary.

This concludes our question-and-answer session, which also concludes our conference for today. Thank you for attending today's presentation. You may now disconnect.