Good day, and welcome to the Magnolia Oil & Gas First Quarter 2022 Earnings Release and Conference Call. [Operator Instructions]. 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 drilling and completing wells and 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 80% of -- nearly 60% of our total company production compared to 1/3 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 start 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 1/3 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 referring 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 and 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 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 continue to have -- we have approximately 0 net debt and expect to generate a significant amount of free cash flow through 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're also operating 2 rigs when production -- 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 -- turned in line 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..

[Operator Instructions]. And our first question will come from Neal Dingmann with Truist..

One, this is largely due to the strong well results you continue to see at Giddings and you anticipate this portion of -- 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 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 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 you -- if we bought in 4% of the shares and we grew the production 6% in the current year, then 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 -- would be higher than 10%..

No. I'd love to hear you -- such a great plan. And then secondly, just maybe operationally, specifically a bit more on Giddings if you could.

Could you speak maybe broadly as to what the -- I don't know, what terms you can -- kind of color you can give on this, but what the aerial extent of the current delineation program? And then how concentrated is the current development side of that program with those 2 rigs..

The development program is fairly concentrated in a couple of areas, maybe totaling less than 100,000 gross acres. However, our understanding of the reservoir has grown a lot over the last year. We spent a lot of effort trying to understand the reservoir better.

And without being too explicit, the aerial extent is growing geometrically because we find in areas that we thought wouldn't work, we found ways to make it work by better drilling techniques or avoiding depleted reservoirs in the path of -- shock is quite thick here, and there are areas that were depleted by the earlier wells.

And if we can avoid those depleted areas, we'll find large-scale pockets of oil, and we think that's working pretty well at this point. And so it sort of opens the size of the aerial extent quite a bit. So we can't really say how much because we don't know exactly, but it does open the aerial extent quite a bit.

So our inventory, we try to keep a 5-year drilling program set. So we always have 5 years, so we know what we can do. But if we could do much, much, much longer than that with 2 rigs. So it actually -- it's a gift that keeps giving. The better we understand, the more we can -- the more growth there'll be over time.

We would view the 6% mid-single-digit growth. Does that include some decline Karnes, probably. So it is a conservative number..

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..

Well, it's something like 20%. It's -- we don't know exactly because it varies -- you don't feel exactly the same well every -- from year to year. So we're drilling longer laterals. We were 4,000 feet a couple of years ago, and we're drilling 8,000 to 10,000 wells. So our productivity is soaring.

The -- we're drilling the wells a lot faster, and less time to spend in the hole, the better off you are. So it's significantly better. Plus $100 oil are we seeing always looks more..

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 right. And we're going to drill some more and we try to -- also trying to fix -- figure out what the right spacing is part of this program to try to optimize each well. And so we've spent some time with that also to try to figure out what the correct spacing is. So we're closing in on that to some extent.

But the answer to your question is that the appraisal program is going 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, I mean, some of the wells that we're drilling will exceed and surpass 10,000 feet.

So last year, we're sort of running 7-ish..

A simple way to look at it is -- virtually every month, we drill that -- take the drill part of it. we drill a well at a record short period of time. And so what's happened is our -- we're going to drill more wells with 2 rigs than we thought we'd 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 well bore..

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 is just -- who 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 the sure dividend. Beyond that, right now, a sensible strategy is to repurchase the shares. I think, 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.

And I think that's the -- for certainly this year, that's really the plan. Once we get beyond that and it becomes more difficult to buy shares or if the stock gods are kind, the stocks start to reflect some time reasonable terminal value for the industry. Right now, they think that the whole industry is going to go out of business in 5 years.

So I think that once we get beyond that, the stock starts to reflect a more reasonable valuation, then we'll look at other ways to return money through dividends. Right now, the focus is on buying as many shares which I think are mispriced over time.

I have more confidence in the product price than I probably ever had in my life, at least for the next few years. And so I think that the reevaluation of the industry from 4% of the S&P and maybe 10% is probably an order over time.

So the focus for now will be on growing the base dividend as we promised and buying in the shares while we remain reasonably priced..

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

Early in the year, you had indicated strong macro environment in the first half. And then you were concerned about a slowdown in second half.

Would love about your updated thoughts on the macro here?.

Well, I don't know. The predictions are always hard especially about the future. And I don't know anybody who's got a particularly good record. For the industry, I don't see much risk during this year. Maybe there'll be some modest line in oil price, but not much because it's so tight.

The oil and gas gods up in the sky or wherever they are located, they looked down on us and they looked at each other and look at the industry over time, the oil and gas gods say, you know, I've given these guys lots of opportunity, and they continue to extract defeat from the jaws of victory. They continue to overproduce.

And this time, we're going to make it until they can't. So we're going to tighten the labor markets, and we're going to tighten the supply chain. And so we keep these oil and gas gods to say at this time, we're going to fix it so they can't overproduce and destroy the good thing. Not that they wouldn't if they could.

And that's what's going on now, and we have this environment where even if you wanted to grow a lot, you couldn't. You can't get the supplies, you can't get labor. You can't drill the wells. And as long as that goes on, I think the product prices will be relatively strong.

A serious recession would hurt oil and gas prices like it hurts almost everything else. And so once when you raise interest rate, what are you doing, where you're punishing autos and housing and the stock market. So I don't know if that brings inflation down or not, but they seem to think it will.

As long as demand stays pretty good, I don't see a bunch of supplies coming on. I don't -- not worried about Russia. I'm sure Russia is selling a fair amount of oil away from the general markets at discounted prices. I'm sure the Iranians are too. So even if this whole thing ended, there wouldn't be that much additional oil that come on the market.

and the demand is very good and the Saudis don't -- I don't think, plan on flooding the market with oil. So we're looking at pretty good product prices for the next couple of years, I think. And natural gas surprisingly strong, basically competing with coal. And so I really think that we're in a pretty good place. Could there be a recession, sure.

Most recessions are caused by a confidence of the Fed. And I doubt if this next one will be a change of that policy or outcome. [indiscernible].

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, I don't think, is at a low price. I want $7 gas or $100 oil. I bought some of each. So it means we avoid -- to avoid the gassier areas and just drill the oilier areas. And now it gives us more flexibility to drill around. But I can't really add as rig as a practical matter. There's no rig to add at a reasonable pricing with a good crew.

I need a good crew, you see, to make it work. And if you wanted to add a rig, you wouldn't get a good crew now. And I don't want bad crews because bad crews make for bad problems. So I think we'll go along and we're not really differentiating between oil and gas anymore because the gas stuff works pretty good, especially the NGL pricing..

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

I just want to say, again, I enjoy when your color, Steve, comes in the form of unfiltered opinions. I don't think you're in for -- I don't think you're looking at a role as a commentator on CNBC, but they can really use you..

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 is it -- what's -- what's 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?.

So we don't have the same issues with land that we have, say, in Karnes or people have in the Permian. So you don't have these land issues because we own so much of this. And so we can always -- and what you have as you drill through the stock, you have zones that are depleted from earlier wells.

The question is how to sort of drill around them or keep yourself from losing circulation as you pass through them. And so we've learned how to do that, and therefore, we can -- it becomes less an issue of the loss of circulation as you pass through it because you know how to deal with that..

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

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

Okay. And then second question, Steve. I'd like to try to get you to opine a little bit more with the benefit of all your experience. You mentioned that you can't pick up another rig now because you'd be picking up the rig at a high rate, and it would have probably -- it'd have a green crew.

As you play the movie forward in your head for Magnolia and the industry into '23, are you concerned that just to pick up on that one issue of crews that you might still have your 2 rigs, but that your crew is going to get paved to start up a new crew somewhere and you're going to wind up with a 50% green crew.

And is that going to happen kind of across the industry and lead to more inflation in '23?.

I don't know about the inflation. Certainly, they've got to do something with a couple of -- with only 2 rigs, controlling the crew is easier, frankly, than somebody who has owning 20 rigs or 25 rigs. We can make a deal with the contractor on the crew. The -- somebody who runs a lot of them, it's really hard to make that kind of decision.

And so the contractor will use those same people to train new ones. I don't know about inflation, but it certainly is -- make it less efficient. It's not placing in the normal sense of the word, but instead of taking 20 days to drill a well, it takes 22..

Right. Not so much inflation, but efficiency could be on the....

Yes. You do have to -- we had this big downturn. A lot of people lost jobs and to reattract them to the industry, you're going to have to pay to do that maybe some layoffs that Amazon would help to maybe get some of their truck drivers. But that's really -- you're going to have to recruit them for somewhere to do this.

Now you can get them out of the community colleges and that sort of thing to start training them on your crews. It takes time, but you can actually do that if you work at it. We don't really have any turnover in our own people and our field hands and stuff. So the industry pays well and gives good benefits.

So I mean, it's not a bad industry to work, but we did have this downturn and a lot of people went off to do other things. And it turns out that maybe some of those other things were 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..