Good day, and welcome to the Magnolia Oil & Gas First Quarter 2021 Earnings Release and Conference Call. All participants will be in a listen-only mode. After today's presentation, there will be an opportunity to ask questions. 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.
MGY Magnolia Oil & Gas
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 flow. 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-digit. 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 that 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 completing wells or 26% of our adjusted EBITDAX to deliver a 3% sequential production growth. Record production at Giddings the driver are better-than-expected production volumes. Giddings' production grew 22% sequentially and was up 45% for 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 D&C capital over the previous four quarters, demonstrating the quality of the acreage. Well costs at Giddings are averaging about $6 million per well and one rig can drill about two wells per month. In our initial core area at Giddings, we now have a total of 28 horizontal wells online. The eight wells added in the first quarter are online with an average production rate 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 to add activity is not like to be realized till later in the year, the biggest impact reflected in 2022. Even with the additional rig, our drilling and 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 into adding small bolt-on acquisitions.
Now that we have a better understanding, returns generated in our Giddings devolvement, we do not have any need for any large scale M&A.
So while it's 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 the share repurchases, we still exited the quarter with $178 million in cash. In summary, we had a great 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. Plus 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 semi-annual 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 is 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 62.3 thousand 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 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. Overall, we expect to run one rig for the full year at Giddings with the 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 61.8 thousand 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 one 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 $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 line 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 non-cash tax expense for the first quarter would have been approximate $20 million on our total net income. Simply put, our pre-tax 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've 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 one-time 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.
We will now begin the question-and-answer session. And the first question comes from Zach Parham with JPMorgan. Please go ahead.
You're now guiding to capital spending of somewhat less than $300 million in 2021, which you talked about being less than 50% of EBITDA.
Given that the 2022 strip is currently around $60, how should we think about spending in 2022? Is that two-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 is not uncorrelated.
And so, if you think we're going to grow in the low end of the single digits - of upper single-digit, we should have significantly less capital than $300 million. And if you think we're going to grow at the high end of it, we'll be closer to the $300 million. And then the same thing will be true next year.
So I think the run rate of the second half for the year in capital, which would be roughly twice what we spent in the first quarter annualized because we're running one rig in the first quarter, we're running mostly one rig in the second quarter. And then as we go into third and fourth quarter, we'll be running two.
So that rate, whatever it turns out to be, will proximate 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 non-operated 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 built into this. The variance around the high end is probably somewhat greater.
And just one follow-up.
You talked about paying no cash taxes for the remainder of 2021.
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, those are physical - 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, more bought by us, 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 and - that given our level of spending and given of the profitability of the business, eventually we'll pay taxes. And while I don't enjoy paying taxes, it's - I dream - 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. Please go ahead.
You alluded to the fact that - in your prepared remarks here that you saw some strong reason Giddings to well performance. I was hoping maybe you could give us a little bit 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 well 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 two things?
Well, so we said we put on basically eight 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 we're - 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.
So it's - 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, pretty remarkable. Again, I think physically if you think about it, the historical fracking not in Austin Chalk, basically just fracked the chalk formation against existing fractures.
Here what we're doing is we're creating some from the frac process, but we're also opening old - existing fracture zones.
And so you get more, call it, non-frac 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. I mean 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'll give - and putting a royalty in there because the royalty is taken out of that, give you an idea 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 eight wells is none of them have been on for the 90 days, but then in a - 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 2021.
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 mentioned M&A opportunities with free cash flow, if I heard you guys right.
Sounds like you mostly think it's pretty small bolt-on type stuff and not really anything chunky available.
Not anything chunky available that would compete. That's the issue. I mean 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 roughly the principle of this. That's why the large deals - there are other people who have different set of alternatives.
As far as buying the shares are concerned, we - as far as buying the shares are concerned, as long as - 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 is reducing the shares or whatever.
And so, if we're going to earn, I don't know what - let's say we just annualized the first quarter.
So, if we're going to earn $1.40, $1.50, buying stock in $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 share 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, its share count declines are 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 or to take those shares off their hand.
The next question comes from Neal Dingmann with Truist Securities. Please go ahead.
Morning all. Steve, just following up on that comment you just had. I mean I agree the shares do look cheap, but again my comment or the 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 the 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. Occasions don't go away.
So to some extent, since we don't sell shares as a company and no plans to do some - buy something for the 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 at the most popular segment in the world. And once people have that view and we could buy the shares cheaply now, we'll do that because we can always accelerate the drilling. My objective is to spend the money wisely as I can over time.
And so the business will grow nicely without pushing that and our finding cost will stay low.
If you start accelerating just to generate free cash flow for what end, I don't know, you will get sloppy and it's just the nature of oil guys.
So this is the way to control our costs. And we can make the growth anything we want it to be.
And so if high growth became more involved, we could probably do that, but right now a growth of 6% to 9% and buying in 4% of the stock every year, strike says it's a rational approach to generating pretty safe 10% per share metrics; 10%, 11%, 12%, 13% metrics on a per share basis, and we think that's should be attractive to a generalist investor.
No, I would agree with your comment, Stephen. And I think you just kind of hit on my follow-up. And it was around your Giddings growth. I mean I'll - my thought was really, these days obviously, seems you mentioned any type of growth, it's so taboo and so - but for you all, as you mentioned, it did take so little capital to boost Giddings.
Just anything else you would think about, I mean how you guys had great growth, would just so, again, given what - I know how investors feel about growth, just - but how cheap it is to grow in Giddings, maybe anything else you could say around that? Thank you, Steve.
Yes. We're putting a second rig on. And most of that will be in Giddings, some in Karnes, in the $65 environment while Karnes is 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 drilling in. 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 managed better that way. In emergency, of course, we can do whatever, but we just manage better if we build slowly and thoughtfully. And again, locations aren't going away and I don't have any - I don't really care what the banks think because 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 that debt needs.
So I think this is that the right strategy for a multi-year program. And what would ruin the strategy or what would change the strategy would be if the stock were to go to some - would double or triple in the same price environment, then the share repurchase strategy wouldn't work anymore and we have to endure more dividends.
The next question comes from Umang Choudhary with Goldman Sachs. Please go ahead.
My first question - most of my questions have been already asked, sir. I have two 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 to look at four new areas and with the spacing of that I don't know. We're still putting together petro physical work.
So there be four wells I think that'll be - then there might be three by the way or some other number, but four 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, do our footprint plus 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.
And any color around the expectations in terms of like whether as oily as your focus area? Do you expect the appraisal program to be more gassier or in the gassier part of your acreage footprint? Just trying to understand
I think we're - we're looking for basically - for our 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 where 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 is in early 2020, you would consider building up 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 cost down the road.
That's something we're actively working on.
So generally the idea is that we'll be able to reduce the number of modern production facilities. We had used centralized production facilities and carry the oil to a trunk line and take that down. It's not very far, not very expensive. And then, we probably put it in a water disposal line to go with it through this 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 - and as the - what it looks like over the next two or three 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 can 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 them right away. 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. Please go ahead.
I just want to ask - I'm sorry if you've 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 picking it on spot pricing or whether you've locked it in for some periods?
The rig rates have not changed very much.
And so - and to same people we have to run the first rig forum and we were there for them during the downturn.
And so, they're here for us now.
So I don't think we - I don't think it's built a lot different.
If you're talking about inflation in the field, inflation is caused by transportation costs in steel and things like that, which everybody knows.
You can see it as 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 toss in a few pennies back to a steel producer or a guy running, driving a truck.
And so you see the price of sand doesn't change for example, but the hauling of the sand costs more.
So I mean that's the sort of thing you're seeing. I mean that's truly American industry in general. We're not having UPS deliver our sand.
Right. 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 there.
Just what's that like now typically?
I mean we average two rigs...
Two wells, yes.
Two 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 you got to take a little - you don't have the pad efficiency.
So you'll see some degradation there as we do drill the three or four of those. But in the development of that that's really all and then the completion just depends - we only use one completion rig and we use it in Karnes and Giddings, just depends on the schedule.
So if we drill a well in January or March or we could get to it right away or it might take a couple months. And again three months - a quarter, well, it's a big deal that somebody studied the stock. From our perspective, it doesn't really make a lot of difference, whether the well start producing in June or July.
So I just - it just depends. Again with small program like ours, small changes turn into big deals, but they're really not.
The next question comes from Nicholas Pope with Seaport Global. Please go ahead.
I was trying to reconcile a little bit the kind of capital - 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 the back of the envelope math, that's struggling to get to a $300 million with a 30 type well count in Giddings during the year. I'm trying to understand if there's maybe some more non-op activity that might be expected in Eagleford and the Karnes area.
Just could you help me out a little bit with the math?
So - yes, 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, included a little non-op activity and some - completion of some docks. But you'd expect that in any quarter. And there were eight Giddings well sort of probably drilled in the quarter.
So that's what a one rig program costs. And if that's all we did, you'd spend $40 million a quarter and it would fluctuate with completing DUCs or what we did in Karnes or whatever. But that's sort of the answer. When we put the second rig on, it'll cost another $40 million a quarter for the full quarter and so you do that. And then the rest would be in the non-op area and to - some of the second rig will be used in Karnes and some these exploration Giddings well, obviously you get a little mismatch on the wells drilled, but that's right. It's a...
And as the - and are you all on track again?
It's a struggle to get - yes, it's a struggle to get the $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 or at least that's the average for 2020, an expectation of $6 million for D&C and for Giddings is that kind of...?
Yes. That's right.
Yes. And then the current wells are less expensive.
Got it. Thanks. That's all I had. Thank you.
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.