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Good day, and welcome to the Magnolia Oil & Gas First Quarter 2021 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, of Investor Relations. Please go ahead.
Thank you, Tom, and good morning, everyone. Welcome to Magnolia Oil & Gas' First Quarter 2021 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 the 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 2021 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.
Thank you, Brian. Good morning, and thank you for joining us today. My comments this morning will focus on our business model and provide an update on our Giddings asset. I will also provide some more details for our plans for the remainder of the year. Chris will review our first quarter results and will provide some additional guidance before we take your questions. Our business model centers around disciplined capital spending and generating significant free cash flows. We limit our capital spending to approximately 60% of EBITDAX, which is intended to generate mid-single-digit production growth. As we shift the balance between Karnes and Giddings, we're going to generate higher production growth with lower levels of capital as a result of the improved efficiencies at Giddings. We plan to spend somewhat less than $300 million to generate year-over-year production growth of 6% to 9%; that is, in the high single digits. The reduced amount of capital needed for this level of production growth provides greater free cash flow for Magnolia to improve its per share value. The optionality the free cash flow provides allows Magnolia to improve its business while also enhancing shareholder returns. In contrast, some of our more leveraged peers have to allocate their free cash flow to reducing their debt. We clearly don't need to do that. First quarter was one of the best quarters in our company's short history. We had record earnings, EBIT margins of 48%, just shy of our goal of 50%, and free cash flow of $100 million. Further, with no oil hedges, Magnolia can benefit fully from the improved oil prices. During the first quarter, we spent just $39 million on drilling and completing wells, or 26% of our adjusted EBITDAX, to deliver a 3% sequential production growth. Record production at Giddings was the driver of our better-than-expected production volumes. Giddings production grew 22% sequentially and was up 45% from the same quarter last year. Oil production at Giddings increased 32% sequentially and was up 73% from the prior year quarter. Our significant production growth at Giddings was accomplished by spending only $91 million of D&C capital over the previous 4 quarters, demonstrating the quality of the acreage. Well costs at Giddings are averaging about $6 million per well, and 1 rig can drill about 2 wells per month. In our initial core area at Giddings, we now have a total of 28 horizontal wells online. The 8 wells added in the first quarter are in line with the average production rate we reported last quarter. The current operated rig at Giddings continues to focus on the initial core area, where we expect to bring online 20 to 24 wells this year. We plan to add a second operated rig this summer to drill wells in both of our asset areas. Production impact of the added activity is not likely to be realized until later in the year, the biggest impact reflected in 2022. Even with the additional rig, our drilling completion costs will be somewhat less than $300 million for the year. Over the last couple of years, a large portion of our free cash flow has gone to adding small bolt-on acquisitions. Now that we have a better understanding of returns generated in our Giddings development, we do not have any need for any large-scale M&A. This allows more of our free cash flow to be used for reducing our share count. We reduced our diluted share count by 4% from fourth quarter levels and expect the second quarter share count to average about 245 million shares. We were able to accomplish our annual share reduction goal in the first quarter alone, but we still plan to buy back about 1% of our shares each quarter. Despite spending $88 million during the quarter on share repurchases, we still exited the quarter with $178 million in cash. In summary, we had a great start to our business in 2021. With the efficiencies and better productivity at Giddings, we were able to do more with less, all while maintaining our low-cost structure and strong balance sheet. Less capital is needed to grow production, resulting in more free cash flow to improve the value of our business. With no need for any large-scale M&A activity, our free cash flow is focused on share repurchases, combined with small bolt-on acquisitions. Finally, we plan to pay our first semiannual dividend in the third quarter. I'll now turn the call over to Chris.
Thanks, Steve, and good morning, everyone. As Steve mentioned, I plan to review some items from the first quarter results and provide some guidance for the second quarter and full year 2021 before turning it over for questions. Starting on Slide 4 of the presentation on our website, Magnolia delivered very strong first quarter 2021 financial and operating results. The company generated total reported net income of $91 million, or $0.37 per diluted share, and adjusted net income of $94 million, or $0.38 per diluted share, both well ahead of consensus estimates. Our adjusted EBITDAX was $151 million in the first quarter, with total drilling and completion capital of approximately $39 million. D&C capital spending represented just 26% of our adjusted EBITDAX during the quarter. As a percentage, this was better than our earlier guidance, mainly due to higher product prices, higher production and lower non-operated capital. Total first quarter production grew 3% sequentially to 62,300 barrels of oil equivalent per day, also higher than our earlier guidance. Our production in Giddings grew 45% from the prior year quarter, with oil production at Giddings growing 73% from the year ago period. Total production exceeded our guidance due to continued strong performance from some of our newer wells in Giddings. Looking at the quarterly cash flow waterfall chart on Slide 5, we began 2021 with $193 million of cash. Cash flow from operating activities during the quarter was $118 million, and cash flow from operations before changes in working capital was $142 million. Our D&C capital outlays, including leasehold costs, was $40 million during the quarter. We allocated $88 million during the first quarter toward our share repurchase efforts, reducing our fully diluted share count by approximately 9 million shares. Since we began our share repurchase authorization in the third quarter of 2019, we have reduced our diluted share count by 20.5 million shares, or by about 8%. We currently have 12.6 million shares remaining under the repurchase authorization. We generated $100 million of free cash flow in the first quarter and ended the period with $178 million of cash on the balance sheet. $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 has an undrawn $450 million revolving credit facility, and our total liquidity of roughly $630 million is more than ample to execute our strategy and business plan. Our strong balance sheet and consistent free cash flow generation is a relative advantage for Magnolia, allowing us to improve our per share metrics, whereas cash flow for many of the more heavily indebted companies is consumed by interest costs or the need to allocate free cash flow to reduce leverage. Our condensed balance sheet and liquidity as of year-end 2020 are shown on Slides 6 and 7. Turning to Slide 8 and looking at our unit costs and operating income margins, our total adjusted operating costs, including G&A, were $10.47 per BOE for the first quarter. Including our DD&A rate of $7.66 per BOE, which is generally in line with our F&D costs, our operating income margins for the first quarter of 2021 were $17.83 per BOE, or 48% of our total revenue, compared to 29% in the fourth quarter of 2020. Turning to some additional guidance for 2021, we expect our full year capital to be below our normal range of 50% to 60% of adjusted EBITDAX, mainly due to higher-than-expected product prices and the improved efficiency of our capital program. While we plan to add a second operated rig during the summer, our total drilling and completion capital is still expected to be somewhat less than $300 million for the full year. The cadence of our activity in capital spending is expected to see a modest increase in the second quarter and further increase during the second half of the year, coinciding with the additional rig and activity. Over all, we expect to run 1 rig for the full year at Giddings, with a second rig drilling in both Giddings and Karnes, with a mix of development and some appraisal drilling at Giddings. Only a small portion of the production impact from the second rig will be seen late this year, with most of the benefit not reflected until 2022. 2021 capital spending and activity is expected to deliver full year production growth of 6% to 9%, compared to 2020 production levels of 61,800 BOE per day. Looking at the second quarter of 2021, we expect production to average 66,000 barrels per day, a sequential increase of 6% compared to the first quarter. As we completed several DUCs in the Karnes area late in the first quarter, most of the company's second quarter sequential volume growth will come from Karnes. This is somewhat a function of running 1 rig during the first half of the year and a matter of timing of drilling and completions between Karnes and Giddings. Oil price differentials are anticipated to be approximately a $3 per barrel discount to MEH during the second quarter. The fully diluted share count for the second quarter of 2021 is expected to be approximately 245 million shares, which is 4% lower than the fourth quarter 2020 levels. We expect our shares outstanding to decline further through the year as part of our ongoing share reduction efforts and as we expect to repurchase about 1% of our outstanding shares per quarter. I wanted to provide some additional information that should be helpful for those modeling our earnings for this year. Following GAAP rules, we do not expect to have any material federal tax expense for the remainder of the year, as a result of a valuation allowance associated with the oil and gas property impairments taken during the first quarter of last year. Had the valuation allowance not been created last year, our noncash tax expense for the first quarter would have been approximately $20 million on our total net income. Simply put, our pretax net income should approximate our total net income for the remainder of the year. Further to this point, we do not expect to pay any material federal cash taxes during 2021. As we have announced previously, last summer we provided notice to EnerVest that we are ending our operating services agreement with the company. That process is now nearly complete, as Magnolia has built out its organization, filled out most open roles with Magnolia employees and taken over the EnerVest-provided services that were part of the original agreement. The transition from EnerVest contract workers to Magnolia employees provides us with better operational control and should reduce our cost structure once the process is complete and into the second half of this year. We expect to take a onetime charge to be reflected in our second quarter results for costs associated with the anticipated termination of the services contract with EnerVest, including costs related to modernizing some of our IT systems and software. We expect to see a meaningful decline in our cash G&A starting in the second half of the year as a result of the end of the EnerVest contract and plan to provide more details around this with our second quarter results. In summary, Magnolia's high-quality assets and continued capital efficiency should continue to generate strong operating margins and sizable free cash flow, allowing us to execute our strategy and improve per-share value of the business. We're now ready to take your questions.
[Operator Instructions] And the first question comes from Zach Parham, with J. P. Morgan.
You're now guiding to capital spending of somewhat less than $300 million in '21, which you talked about being less than 50% of EBITDA. Given that the '22 strip is currently around $60, how should we think about spending in '22? Is that 2-rig program for the full year a reasonable expectation at this point? And I guess, just more generally, how do you think about the balance between production growth and free cash flow generation?
I think you should view the amount of growth you have in your view and the capital spending as not uncorrelated. And so if you think we're going to grow in the low end of the single digits of the upper single digits, you should have significantly less capital than $300 million. And if you think we're going to grow at the high end of it, it will be closer to the $300 million. And that same thing will be true next year. So I think the run rate of the second half of the year in capital, which would be roughly twice what we spent in the first quarter annualized, because we're running 1 rig in the first quarter, we're running mostly 1 rig in the second quarter, and then as we go in the third and fourth quarter we'll be running 2. So that rate, whatever it turns out to be, will approximate what you should see next year. That would generate, all things being equal, more growth than we're showing for this year because we're basically running more rigs. So the range, the 6% to 9% range, actually reflects differences in our guess as to what nonoperated activities would generate, since we don't really know that, it's picked up some recently but it's still not a lot, and how many exploration-style wells we drill in Giddings versus development wells and how the exploration-style wells turn out. So that's really the variance. And because of the variance we've built into this, the variance around the high end is probably somewhat greater.
Got it. And just one follow-up. You talked about paying no cash taxes for the remainder of '21. Just given that Magnolia is consistently profitable and generates free cash flow, when do you anticipate becoming a cash taxpayer?
It's actually a more complicated question than you probably would guess. The B shares that we have, which are about 27% of the total shares, they're actually partnership units with a voting right attached to them. And so they pay their own taxes. And when they're sold, they have to be converted to the A shares. It's the only way to sell them or bought by us; it doesn't matter which. We get a step-up in tax basis and that provides shelter, going forward. So our ability to predict this depends on the number of B shares outstanding. So it is true, for sure, that given our level of spending and given the profitability of the business, eventually we'll pay taxes. And while I don't enjoy paying taxes, as a person I've always dreamed of being the nation's largest taxpayer. So it's sort of a good thing.
The next question comes from Leo Mariani, with KeyBanc.
You alluded to the fact in your prepared remarks here that you saw some strong recent Giddings well performance. I was hoping maybe you could give us a little bit of color around that. And then, additionally, just also wanted to ask about maybe some of the wells that came on in 2020 at Giddings, particularly some of the ones early in the year before you shut things down. Really, the question around that is just, how is the longer-term well performance also looking at Giddings? I think as you folks know, historically, Austin Chalk wells sometimes haven't held up great over the long term. I think, obviously, you guys are targeting kind of a better section here of better permeability. So maybe you could just kind of speak to those 2 things.
Well, we said we put on basically 8 wells during the quarter, which ties to the drilling rate. So that's what that is. Virtually none of them have been on for 90 days. And so we don't -- reporting 30-day production really isn't very useful for this because the wells tend to start out a little noisy and build up over time, although it's been a little better lately. You can actually see what the older wells are doing because this is how many wells we're putting on, and the production clearly is not declining sharply. So the answer to your question is the decline rate is much less, say, than Karnes wells. And the better wells are really quite strong in that period. But you can actually see it in the production because we're not drilling enough wells to make the production grow if we were faced with 50% declines in the other wells. So it's been pretty remarkable. Again, I think physically, if you think about it, the historical fracking done in Austin Chalk, basically, just fracked the chalk formation against existing fractures. Here, what we're doing is we're creating some from the frack process, but we're also opening old existing fracture zones. And so you get more, call it, non-frack type production going into the mix. So I think the answer to your question is that, to some extent, it's in the finding cost. Our finding cost is...
Less than $5.
Less than $5 of BOE for the wells. And that continues to go down as we get more data. So that will give you ?- and putting a royalty in there, because the royalty is taken out of that, will give you an idea of what the wells are producing. So I don't think it's a great mystery that it's significantly lower than at Karnes and produces a lot more oil over its life. But the reason we didn't talk about the 8 wells is none of them have been on for the 90 days. But the ones that have are probably a little above average, above the average we showed you. So no reason really to put in hyped numbers like that.
Okay. That's helpful color, for sure. And just in terms of returning capital to shareholders, you guys have obviously been very aggressive with the buyback. Clearly, you've indicated that you're going to start to bring a variable dividend into play here as we get later in the year in '21. So maybe you can just talk about philosophically how you allocate some of that free cash flow to the variable dividend versus the buyback. And you also mention M&A opportunities with the free cash flow, if I heard you guys right. It sounds like you mostly think it's pretty small bolt-on type stuff and not really anything chunky available.
It's not anything chunky available that would compete. That's the issue. There's stuff to buy, for sure, but it would be dilutive to our results. And you might stumble into diluting yourself, but you shouldn't go out deliberately to do that. So that's really the principle of this. That's why the large deals, there are other people who have a different set of alternatives. As far as buying the shares are concerned, as long as the -- we look at the earnings as sort of actually valuable information. Our finding costs and our DD&A rate are approximately the same, as Chris pointed out. So the earnings we have is available for improving things. And so that's reducing the shares or whatever. And so if we're going to earn, I don't know, let's say we just annualize the first quarter. So if we're going to earn $1.40, $1.50, buying stock in that $10, $11 does not strike us as expensive. So as long as we can do that, that will be the principal focus. Over time, as we reduce the share count, the amount of dividends will go up because I view the dividend as sort of a lump sum, and it's just divided by the number of shares outstanding. So while we might pay a little less than we might otherwise pay in this year or maybe next year, as the share count declines there's just more money to pay more dividends per share. And that's really the goal. As long as the stock is clearly inexpensive, the priority will be there. And there are people who don't want to own oil stocks or don't want to own us. Anybody who has got 1 million shares can call up Mr. Stavros, and we'll be glad to arrange to take those shares off their hands.
The next question comes from Neal Dingmann, with Truist Securities.
Steve, just following up on that comment you just had, I agree: the shares do look cheap. But again, my comment or a question, I guess, would be, is your Giddings returns are so phenomenal. So I'm just wondering, how do you, when you and Chris sort of debate Ops versus the finances behind that, when you think about stock buybacks versus the incremental Giddings delineation, using that money for?
The Giddings is there forever. The locations don't go away. So to some extent, since we don't sell shares as a company and no plans to buy something with a bunch of watered stock, our objective is to keep the stock in a reasonable range. Yes, we could spend more money and grow more. There's no argument about that. But the locations will still be there. And the opportunity to buy the shares is sort of now. It's not the most popular segment in the world. And as long as people have that view and we can buy the shares cheaply now, we'll do that, because we can always accelerate the drilling. My objective is to spend the money as wisely as I can over time. And so the business will grow nicely without pushing it, and our finding costs will stay low. If you start accelerating just to generate free cash flow, for what end I don't know, we'll get sloppy, just the nature of oil guys. So this is the way to control our costs. We can make the growth anything we want it to be. And so if high growth became more in vogue, we could probably do that. But right now a growth of 6% to 9% and buying in 4% of the stock every year strikes us as a rational approach to generate pretty safe 10% per-share metrics; 10%, 11%, 12%, 13% metrics on a per-share basis. And we think that should be attractive to a generalist investor.
I would agree with your comments, Steve. And then I think you just kind of hit on my follow-up. And it was around your Giddings growth. My thought was really these days, obviously, and as you mentioned, any type of growth, it's so taboo. But for you all, as you mentioned, it takes so little capital to boost Giddings. Just anything else you would think about? You guys had great growth with just 1 rig. So again, given what I know how investors feel about growth, but how cheap it is to grow in Giddings, maybe anything else you could say around that.
We're putting a second rig on, and most of that will be in Giddings, some in Karnes. In a $65 environment, while Karnes still isn't as good as Giddings by North American standards, it's probably still some of the best money you could spend. And so that's sort of the balance we're doing. And we'll look into next year to see what needs to be done, but I don't want ratcheting up the rigs and then bringing them down and that sort of thing. So I try to be sure that we're able to continue whatever we're doing because we just manage better that way. In an emergency, of course, we can do whatever, but we just manage better if we build slowly and thoughtfully. And again, the locations aren't going away. And I don't have any -- I don't really care what the banks think. The only reason we don't reduce our line of credit is people would misinterpret it. So we just don't have that kind of debt needs. So I think this is the right strategy for a multiyear program. And what would ruin the strategy or what would change the strategy would be if the stock were to go to some huge, would double or triple in the same price environment. And then the share repurchase strategy wouldn't work anymore, and we'd have to endure more dividends.
The next question comes from Umang Choudhary, with Goldman Sachs.
My first question -- most of my questions have been already asked. I have 2 quick ones for you. The first question was around Giddings appraisal program and your expectations from that program as you add the second rig this summer.
So some of it, the second rig, will be used for pad drilling and some will be to look at 4 new areas. And with the spacing of that, I don't know. We're still putting together the petrophysical work. So there will be 4 wells, I think, that will be ?- and there might be 3, by the way, or some other number, but 4 is currently where we are now. And they'll be spaced over the year to look for areas where, basically, it's look for areas where we can economically lease more land to build the footprint in the areas and see if we can find some areas where we can add to our footprint. It's less about the production, because we've probably got enough in the core area for a number of years. But I don't want to -- since we've got this on our way to being figured out, I don't want to lose the first-mover advantage.
Got it. And any color around the expectations in terms of, like, whether it will be as oily as your focus area? Or do you expect the appraisal program to be more gassier or in the gassier part of your acreage footprint? Just trying to understand [indiscernible].
I think -- we're looking, basically, for a Giddings well, about 50% oil. And there might be some that are 40% oil, there might be some that are 60%. But when we get through, we're looking for a balance. The gassier parts, while we had a good day for gas this last quarter, it's not a -- it's still a pretty weak commodity. And until we get gas prices that are regularly over $3, or so, I'd rather focus on the oilier parts.
Got it. And my second question, follow-up question, was really around the infrastructure build-out in Giddings. I think last you mentioned was that if the program is successful, this was in early 2020, you would consider building a pipeline infrastructure. But the trucking cost itself is lower because your assets in Giddings are located pretty close to the refining demand centers. I just wanted to get your latest thoughts around potential to develop the pipeline of infrastructure to reduce costs down the road.
That's something we're actively working on. So generally, the idea is that we'd be able to reduce the amount of production facilities we had, use centralized production facilities and carry the oil to a trunk line. And to take that down, it's not very far, not very expensive. And then we would probably put in a water disposal line to go with it for the same area. And it's not a lot of money to do it, but it would generate significant efficiencies for us. And as the business, what it looks like over the next 2 or 3 years, it's clear we can probably do that. We may have some people come in and ship on our line, too. But generally speaking, we see opportunities to do that. Because you want to make sure you had enough locations and you could figure out where they were before you put the line in. But right now, we have enough line of sight to probably do that. The principal issue is getting the right of way. It's not whether the line makes sense. So you have a bunch of rich people live in River Oaks, who have ranchettes there. And so nobody wants a pipeline in their ranchette. So that's the fundamental issue.
The next question comes from Noel Parks, with Tuohy Brothers.
I just wanted to ask on, and sorry if you touched on this already, the second rig that you're going to be bringing on. I was just curious about the rate you got for that and what the market looks like and whether you're taking it on spot pricing or whether you've locked it in for some period.
The rig rates have not changed very much. And it's the same people we have who run the first rig for them, and we were there for them during the downturn. And so they're here for us now. So I don't think it's a lot different. [indiscernible] inflation in the field. Inflation is caused by transportation costs and steel and things like that, which everybody knows. You can see they talk about it on television every day. So it must be right. So that's where the inflation is. But I would also add that there's a modest amount of inflation in oil price. And so the margins in this are -- you're tossing a few pennies back to a steel producer or a guy driving a truck. And you see the price of sand doesn't change, for example, but the hauling of the sand costs more. So that's the sort of thing you're seeing. But that's true in American industry, in general. We're not having UPS deliver our sand.
And could you just walk through the components of your cycle time now, just, on average, your drill days, completion days, and if there's a rig [indiscernible] in there? Just what's that like now typically?
We average 2 rigs...
2 wells.
2 wells a month. The actual drilling time is less than that, but that counts moving the rig and that sort of thing every so often. And I don't think that changes very much. In some quarters, it might be a little more or a little less depending on how many moves of it. When we do the so-called exploration wells, those are single wells and that take a little -- you don't have the pad efficiency. So you'll see some degradation there as we drill the 3 or 4 of those. But in the development, that's really all. And then the completion just depends -- we use 1 completion rig and we reuse it in Karnes and Giddings. It just depends on the schedule. So if we drill a well in January or March or whatever you want to say, we could get to it right away or it might take a couple of months. And again, 3 months, a quarter, while it's a big deal to somebody studying the stock, from our perspective it doesn't really make a lot of difference whether the well starts producing in June or July. So it just depends. Again, with a small program like ours, small changes turn into big deals, but they're really not.
[Operator Instructions] The next question comes from Nicholas Pope, with Seaport Global.
I was trying to reconcile a little bit kind of the CapEx guidance for the year. I think coming into the year you were talking about expecting an average of $6 million on Giddings wells to drill and complete. Just kind of back-of-the-envelope math, I'm struggling to get to a $300 million with a 30-type well count in Giddings during the year. And I'm trying to understand if there's maybe some more non-Op activity that might be expected in Eagle Ford in the Karnes area. Just could you help me out a little bit with that math?
Your issue is sort of right. So you don't have to do it even more than that. If you look at the first quarter, we spent about $40 million, including a little non-Op activity and some completion of some DUCs, but you'd expect that in any quarter. And there were 8 Giddings wells, sort of; 2, 4, 6 probably drilled in the quarter. So that's what a 1-rig program costs. And if it's all we did, you'd spend $40 million a quarter. And it would fluctuate with completing DUCs or whatever we did in Karnes or whatever. But that's sort of the answer. When we put the second rig on, it will cost another $40 million a quarter for a full quarter. And so you do that. And then the rest would be in the non-Op area because some of the second rig will be used in Karnes and some of it will be done to drill these exploration Giddings wells. So you get a little mismatch on the wells drilled. But that's right.
And are you on track with that?
It's a struggle to get to $300 million, yes.
It's a good problem. It's a good problem. And you all are on pace on that? I think you all talked about kind of entering the year around $6.2 million, or at least that's what you averaged for '20, an expectation of $6 million for D&C for Giddings. Is that kind of on track?
Yes, that's correct. And then the Karnes wells are less expensive. Okay. I think we're done.
This concludes our question-and-answer session, which also concludes today's conference call. Thank you for attending today's presentation. You may now disconnect.