Magnolia Oil & Gas Corp Q3 FY2021 Earnings Call

Good morning, and welcome to the Magnolia Oil and Gas Third Quarter 2021 Earnings Release and Conference Call. All participants will be in a listen-only mode. Please note, this event is being recorded. I would now like to turn the conference over to the Vice President of Investor Relations, Mr. Brian Corales. Please go ahead, sir.

Thank you, Chris, and good morning, everyone. Welcome to Magnolia Oil and Gas’ third 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 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 third quarter 2021 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. Good morning, and thank you for joining us today. My comments this morning provide a brief update on our business and operations, how we plan to allocate our free cash flow for the remainder of the year. Chris will then review our third quarter results, provide some additional guidance before we take your questions. Our strong third quarter financial results demonstrate the quality of our assets and the efficiency of our capital program. We continue to execute our business model, which prioritizes disciplined capital spending, moderate production growth, high pretax margins, and low levels of debt. These principles, combined with an improved lower overall cost structure, as well as unhedged production, allowed us to achieve several records during the quarter, including EBITDAX, free cash flow, net income margin, and earnings per share. We generated $143 million of free cash flow after capital outlines and interest on our debt and repurchased 5 million shares of stock during the third quarter, or about 2% of our total outstanding shares for approximately (indiscernible), despite the $79 million allocated to share value-enhancing activities; our cash balance grew by nearly 30% during the quarter to $245 million. For the year-to-date, the largest use of our free cash flow has gone towards opportunistically repurchasing our stock. So far this year, we have repurchased 22.6 million shares or about 9% of the total shares outstanding. When compared to the fourth quarter of 2020's fully diluted share count, we have returned 9% to our shareholders in the form of share repurchases for the first nine months of this year. Since establishing the share repurchase program in the third quarter of 2019, we have spent approximately $396 million acquiring our own stock and reducing our diluted share count by 34 million shares. Our share repurchase efforts continue to enhance our per share metrics, and we expect to continue to repurchase at least 1% of our shares each quarter. Magnolia also paid its first interim semi-annual dividend of $0.08 per share during the third quarter, which is secured with oil prices under $40 a barrel. We plan to make the remaining dividend payment in the first quarter of 2022, based on our full year 2021 results and adjusted for oil prices of $55. Our total production volumes grew 4% sequentially during the third quarter, as a result of continued strong well performance. Despite lower non-operated activity, we invested only 30% of our EBITDAX on drilling and completing wells. The quality of our asset base is reflected in the continuing overall growth of our production volumes, low reinvestment rates, finding costs, and high full cycle margins. We currently have two operated drilling rigs across our assets and plan to remain at this level into next year. At current product prices, this level of activity would result in D&C capital programs well below our cap of 55% for our adjusted EBITDAX. One rig will continue to drill development wells at our Giddings asset. While still in the early stages of development, Giddings' results of our drilling program have become more repeatable and increasingly predictable. The second rig will drill wells in both Karnes and Giddings areas, including some appraisal wells in Giddings. We continue to see improvement in our operating efficiencies at Giddings while maintaining well productivity. The 2021 development playoff program has averaged four wells per pad with lateral lengths averaging greater than 7,000 feet per well. This compares favorably to the prior year where we averaged less than three wells per pad with average lengths about 6,000 feet. More wells per pad, combined with longer laterals, while increasing the average drilling feet per day, have helped drive further efficiencies at Giddings, partly offsetting some materials and oil field-related inflation. Our ability to generate moderate annual production growth with strong operating margins, together with our ongoing share purchase program and the payment of a secure, sustainable, and growing dividend, are important components of Magnolia’s total shareholder return proposition. I’ll now turn the call over to Chris Stavros.

Thanks, Steve, and good morning, everyone. As Steve mentioned, I plan to review some items from our third quarter results and provide some guidance for the fourth quarter and some initial thoughts for 2022 before turning it over for questions. Starting with Slide 4 in the presentation found on our website, which shows a summary of our third quarter, Magnolia delivered very strong third quarter 2021 financial and operating results, achieving several records. The company had adjusted net income for the quarter of $158 million or $0.67 per diluted share, compared to total net income of $116 million or $0.48 per diluted share in the second quarter of this year. Our adjusted EBITDAX was $221.5 million in the third quarter with total D&C capital at $67 million or 30% of our EBITDAX. Magnolia’s fully diluted share count declined by 6 million shares sequentially, averaging $236 million during the third quarter. Total production volumes grew 4% sequentially to 67.4 Mboe/d of oil equivalent per day in the third quarter. Production in Giddings now represents 55% of total company volumes, as Giddings has grown by 80% year-over-year. Sequential improvement in our quarterly financial results benefited from higher product prices, especially for natural gas and NGLs, increased production volumes, and lower total costs. Product prices have risen further into the fourth quarter, and as a reminder, we’re completely unhedged on all our oil and gas production. Looking at the quarterly cash flow waterfall chart on Slide 5, we began the third quarter with $190 million of cash. Cash from operations before changes in working capital was $211 million during the period, with working capital changes and other small items benefiting cash by $6 million. Our D&C capital spending, including land acquisitions, was $68 million, and we generated free cash flow of $143 million during the third quarter. Cash allocated towards share repurchases was $75 million, and we paid our first dividend of $0.08 per share in September, totaling $19 million. We ended the quarter with $245 million of cash on the balance sheet, or more than $1 per share. Slide 6 shows our cash flow through the first nine months of 2021. For the year-to-date, we generated cash from operations of $528 million before changes in working capital. During this nine-month period, we incurred $163 million drilling and completing wells. We spent $284 million on share purchases and paid $19 million in dividends. Summarizing our progress during the first nine months of the year, we’ve grown our total production by 11% from fourth quarter 2020 levels, reduced our diluted share count by 22.6 million shares or 9%, leading to 20% production per share growth over the period. This growth was all organically driven without incurring any debt while building $52 million of cash. Looking at Slide 7, this illustrates the progress of our share reductions since we began repurchasing shares in the third quarter of 2019. Since that time, we have reduced our total diluted share count by 34.1 million shares or approximately 13% in two years. We plan to continue to repurchase at least 1% of our outstanding shares each quarter and currently have 8.5 million shares remaining under our repurchase authorization. Management’s philosophy is to maintain a strong balance sheet, and we do not plan to issue any new debt. Our $400 million gross debt is reflected in our senior notes, which are not callable until next year and do not mature until 2026. We have an undrawn $450 million revolving credit facility and total liquidity of $695 million, including our $245 million of cash. Our condensed balance sheet and liquidity as of September 30 are shown on Slides 8 and 9. Turning to Slide 10 and looking at our cash cost and operating income margins, our total operating costs and expenses declined by nearly $10 million sequentially despite the increase in product prices. Most of the improvement was in the form of lower G&A expenses and other associated costs as a result of the termination of the operating services agreement with EnerVest in the second quarter. Our total adjusted cash operating costs, including G&A, were $9.66 per boe in the third quarter, representing a 14% sequential decline compared to the second quarter of 2021. Including our DD&A rate of $7.74 per boe, which is generally in line with our finding and development costs, our operating income margin for the third quarter was $27.66 per boe or 60% of our total revenue. Turning to guidance for the fourth quarter, we continue to run two operated rigs across our assets and expect our fourth quarter capital to be approximately $80 million. This is lower than our earlier guidance and primarily due to ongoing efficiencies in Giddings. Total production is expected to be in the range of 68,000 to 70,000 barrels of oil equivalent per day during the fourth quarter. As I mentioned earlier, we are completely unhedged for both our oil and gas production and should benefit from any further improvement in product prices. Oil price differentials are anticipated to be approximately $3 per barrel discount to MEH during the fourth quarter and in line with recent quarters. We expect our fourth quarter 2021 effective tax rate to be approximately 2%. The fully diluted share count is expected to be approximately 232 million shares in the fourth quarter, and we expect this to decline further into next year as we continue repurchasing our shares. Looking into 2022, our current plan is to continue to run two operated rigs on our assets, and our operated activity should be similar to the level seen during the second half of 2021. One rig will continue to drill development wells in Giddings, while the second rig will drill a mix of development wells in both Karnes and Giddings, in addition to drilling some appraisal wells at Giddings. This level of activity should generate year-over-year production growth in the mid-to-high single digits. As Steve mentioned earlier, we continue to see improvement in our operating efficiencies at Giddings while maintaining well productivity. Some of these improvements include increased drilling efficiencies up 10% compared to last year in terms of drilling feet per day, a 14% increase in average lateral lengths per well to more than 7,000 feet, and a greater than 30% increase in the average wells per pad, leading to fewer pads. Since we’re still in the early stages of development in Giddings, these improvements should allow us to partially mitigate some of the materials and oil field inflation into next year. To summarize, Magnolia’s high-quality assets and capital efficiency should continue to generate strong operating margins and sizeable free cash flow, allowing us to execute our strategy. Our strong balance sheet provides a measure of security amidst product price volatility and is also an advantage in creating optionality for us to opportunistically repurchase our shares, pursue small bolt-on accretive acquisitions, and pay a safe, sustainable, and growing dividend. We’re now ready to take your questions.

Thank you, sir. The first question comes from Neal Dingmann of SunTrust. Please go ahead.

Good morning all. Steve, great quarter by the way. I can’t help but notice that you continue to have very impressive efficiencies that I believe resulted in this 4% sequential production growth with only about a 30% EBITDA spend. So my question around that is would you suggest the crux of this is coming from Giddings upside or really just what else should we read into this?

Yes, it’s really driven by Giddings. The current results are pretty predictable. Our costs are predictable, and production is reasonably predictable. The variation from running two rigs means you’re going to have some variation; a well gets delayed or starts a week earlier or later. It looks like something’s happening, and really nothing’s happening, but it’s basically the efficiencies at Giddings. We continue to look for additional opportunities there outside the current area, and we’ll continue to do that in the next year. The only change I see is that we haven’t had a lot of non-op activity. It’s been much less than historical, and generally speaking, the non-op was like running half a rig for the year and it’s maybe half of that this year, maybe not even that. So, if that continues, we may add a rig sometime next year to compensate for the non-op. But that’s the only change I see, and that rig would probably be focused on new opportunities in the Giddings area. We see a number of areas that look interesting, and we’ve drilled some wells. We don’t have 90 days of results to talk about, but I remain optimistic about it over the next decade or so.

Great points. That’s kind of what I thought on Giddings. And then just to follow up, you’ve bought back quite a fair amount of stock now. I’m just wondering, given that your stock has gone up like others, do you still see the discount when you look at the options to do with the shareholder return? Does that still look to be the most accretive, the best use of your proceeds? Or maybe just talk about that a little bit, given the run that you all have had?

I don’t – for 40 years, I’ve never talked about the value of the stock. So, I’m not a stock market expert. If I were, I’d be wrong around half the time; maybe more, but at least half, because it’s nearly wrong or right. So, I guess it’s 50/50. So the stock depends on your view about oil prices. The industry works reasonably well at $60 oil and works almost too well at $85. I’m not a believer in $85, but $60 works really well for us. The share repurchase makes sense; we actually have a sizeable shareholder and I don’t want him harming the existing shareholders. So we buy shares in quantity at the same price he gets, which is basically set by the market forces. That’s worked out for us. I don’t know what our average price was, about $13 or something—less than $13 for all the shares we purchased. It’s worked out well for the people who bought the stock in the offering, and I think it’s worked out well for the shareholders. The stock’s gone up a lot, that’s for sure. Luckily my wife doesn’t compute this for me. She does count dividends, but I just – I hate to get into valuation. And practically speaking, once we set the dividend in February, we could fairly easily grow that dividend 10% a year for a very long time. For me, that’s an attractive investment. It’s not Tesla or something like that, but it’s a fairly attractive investment. That’s how I think about it—how much can we distribute that doesn’t harm our growth?

Thank you again.

The next question is from Leo Mariani of KeyBanc. Please go ahead.

Hi guys. Can you hear me?

Yes. Now we can hear you.

Okay, great. I just wanted to dig a little deeper into Giddings here. Clearly, you guys have increased your ability to drill more wells per pad and longer laterals. I know you’ve kind of historically talked about a rough $6 million type well cost. But clearly, laterals are getting longer. So, I just wanted to get a sense that maybe you could give us a little idea of kind of what the cost per foot may have done during the course of 2021. It sounds like you guys are optimistic that you might be able to continue to reduce those maybe a little, even in the face of inflation. Any comments you could make on results in the development area, the 70,000 development area Giddings, I think you guys did say prepared remarks that they’re looking more consistent these days, so maybe a little more color if you had around that?

Yes. So in the existing area, it looks very much like what we showed you before. We drill more wells. There really isn’t enough difference to talk about that. It’s a little better, but it’s not – it’s about the same. We have a repeatable model, so it is designed to do that. It’s not designed for large swings. Outside of it, we continue to look for areas. Some of them are a little gassier, but the economics are the same, especially now with gas and NGL prices. So, the economics are basically the same, even though you’re drilling a gassier well, because there’s always some oil—a fair amount of oil associated with the wells. I’m pretty optimistic about that over next year. We were cautious this year on our capital and our spending; and we’ll be cautious next year, but probably a little less cautious next year than we were this year. I think the Giddings program is working reasonably well to the cost per well and we’ve basically overcome inflation so far. The inflation is primarily driven by steel and labor costs, but I’m really not bothered by labor costs. We want good crews; we want the best crews. If you have to pay a few dollars more per hour or whatever it is, I’m not worked up over that. These are small costs. I tell people this is not about 3:00 AM, or we got to raise the price of the Scotch tape in order to pay for the stock. We’ve already got the raise, there’s no question about passing it through. So, I just think that if costs go up, the total cost might go up by $1 or $2—that’s all we see right now. It’s driven by the fundamentals, the well cost. I don’t think we’ll move very much even with a little longer laterals and stuff, it’s doing what it’s supposed to do, and we’re getting better at it. So, I would’t worry about this unless you see a lot more inflation and craziness. If companies start increasing their capital program by 100% to capture this, you put more pressure on the service companies. I think that’s one thing. With a small program, we can have good crews and manage it reasonably well. Other companies running 25 or 30 rigs have a lot more complexity, so with two or three rigs, we have the advantage of keeping this under control.

Okay. That’s helpful. And just a couple things around some of the comments that you folks made. Steve, you did mention potentially adding what sounded like a third rig in 2022 to offset the fact that there isn’t much non-op activity. I just wanted to make sure I understood that. Would that be kind of a partial rig for the year to compensate for a lack of runoff?

It’s definite for a short period of time, and we probably would send the development or exploration activity to that rig; you’d be drilling maybe two wells with it. That would be simpler to do, and then we could focus the other two rigs on the pure development. The idea is that there’s a certain number of net wells in our mind to drill the production and growth we’re looking for. We’re not getting the net wells, because we overestimated how much this year, and the Giddings wells did better than we thought. It’s compensated for some of that, but we still have a vision of what the net well count ought to be. So, the rig would operate for some time in the spring and for a relatively short period to ensure we drill the right number of net wells. It’s not going to generate a lot more capital spending; we’re already spending such a low level—only around 30% of our EBITDA—it wouldn’t be the end of the world to raise that to 40%.

Yes. And that makes a lot of sense for sure. And then just a couple number clarifications. I noticed that in the last couple quarters, cash taxes have started to come in a little bit; they were kind of zero last year, so I wanted to see if you guys had any thoughts on where those may go. Also, I noticed on the oil cut: it was 49% in the second quarter, 46% in the third quarter. Where do you anticipate that going as we get into 4Q here?

We’ll let them answer about the cut. But as far as the taxes are concerned, if we continue to spend that 40%, 45% and have these earnings, our financial statements are fairly accurate because we’re looking at real finding costs, while we have some tax loss carry-forwards and some increased DD&A from the conversion of the B shares, eventually, you’re going to pay taxes. It’s probably not going to be at a full tax rate next year, but I think cash taxes will go up some. I really don’t know how much, but it’s not a huge number. If you only spend 35%, 40%, and you’re generating EBIT margins of 50%, 60%, at some point you’ll pay taxes, which is not the end of the world—it’s better to pay taxes than generate an operating loss.

No doubt. All right, guys, I appreciate it. Thank you.

I hope that answers the question on the cut.

Yes. I think on the cut, and the oil cut, part of it is timing, drilling timing—and part of it is certainly for this year is a bit of the lower non-op spending and drilling activity in Karnes that Steve mentioned. I think had that come in as we had originally expected you probably would have had the oil cut a little bit higher. That said, what we’re seeing in Giddings is certainly strong on the oil cut and relatively better than what we thought early days.

Thanks guys. Appreciate it.

Thanks.

The next question is from Umang Choudhary of Goldman Sachs. Please go ahead.

Great. Thank you for taking my question. Just one from me. Steve, you mentioned the sector looks healthy at a $60 oil price and oil prices are currently much higher. I would love your thoughts on the macro and your long-term oil price expectation of $55. There are a lot of moving pieces here on the macro. Say oil prices are higher, longer term. How does that impact your free cash flow deployment between dividends, share repurchase, organic drilling, and completions?

Well, I’m sort of return-driven. If oil prices were say $65 or $70 on a long-term basis, rather than my view of around $60, we eventually will have the EnerVest shares gone; they’ll out to whatever level they’re going to be. Then we’re looking at buying shares in the open market, which is very difficult to do at this point due to low volumes. So, it limits what we can do regarding share repurchases. It leaves us with dividends. I think that’s your answer.

And then given you have like a cap of 50% towards dividends, would that mean that a variable dividend would be on the cards once the EnerVest shares are gone?

No, I don’t like ratable dividends. Dividend investors care about three things: balance sheet quality, dividends paid out of earnings, and growing dividends. If we have excess, we could just pay a special dividend and it wouldn’t be part of the normal dividend stream. Our working assumption is that once you see the dividend in February, you can plan on at least a 10% increase every year. We want to keep that for the standard dividend investor, and if we build up too much cash, we can distribute it one time or sort of thing. My wife would like that.

That makes a lot of sense. Thank you.

Thank you very much. The next question is from Charles Meade of Johnson Rice. Please go ahead.

Good morning, Steve, and Chris, and the whole crew there. I’d like to go back to the question of the product mix for Q4. I appreciate your earlier comments that it relates to non-op activity, particularly in the Karnes area, which can be difficult to forecast. Are there things happening in 4Q with your turn-in-line schedule or other things that would make the mix change versus 3Q? It looks like there was actually a slight decline in oil quarter-over-quarter, and I’m guessing that, assuming nothing else changes, I would expect to see that same trend play out in 4Q, especially with the strength in Giddings. What are the pieces there?

Well, don’t forget that most of the wells that are going to be producing in the fourth quarter are producing now; we’re halfway through the quarter. So whatever we do is probably going to affect the first quarter more than it will affect the fourth quarter at this point. I think it’s roughly similar to the third quarter because the carryover works that way. You lose sight of the fact that one or two or three or four or six wells doesn’t move the thing very much. While I’m sure some people believe natural gas prices and NGL prices will double from here, we are attracted to drilling in gas and NGL areas, because the profitability on those wells is exceptional. We’ve got a lot of NGLs; we were getting, I think, $9 a barrel for NGLs a year ago, and now we’re getting over $40.

And Charles, we did tell you last quarter that we were steering some of our activity towards completing some gassier wells in Karnes and some ducks. That had an influence over the cut in the third quarter and will dribble into the fourth quarter as well.

A little more gassy and it was a deliberate way of thinking about it because I view $5 gas as a lot of available gas in the U.S. If it stays at $5 for too long, you’re going to have a lot more production, so despite the hedging.

Thanks for that, Steve.

Thanks.

The next question is from Noel Parks of Tuohy Brothers. Please go ahead.

Hey, good morning.

Good morning.

Just had a couple of things. As you look ahead and plan various scenarios, are we at the point that as you essentially self-fund your maintenance drilling, is the interest rate environment now irrelevant or neutral in terms of how you forecast your cost of capital?

For us, we’re not borrowers of money, and when we said, I didn’t even want to borrow the $400 million that we did when we started—so we got $24 million of interest expense roughly. We could borrow cheaper than that now, but I don’t think with the kind of returns we’re making even at $60, $65 oil, I’m not sure leverage is particularly helpful. We’re not focused on that. It doesn’t matter to us what the interest rate environment is. The key is about demand, and demand is going to be strong in the next year.

Thinking about the Eagle Ford from a technology standpoint, do you view the Eagle Ford as having essentially caught up with the technology advances from other basins? Is there still fruit to harvest or a gap that could still be closed?

Yes. The Eagle Ford, especially in the Karnes area, has room for more efficiency improvements. While Karnes is extremely well-developed because the wells were so good, areas less efficient. For us, we can put our capital to work in Giddings or some Karnes stuff and make a lot more money over the next five years, rather than trying to do some kind of science project in a sort of marginal production area.

Okay, great. Thanks a lot.

Thank you.

Thank you very much. Ladies and gentlemen, we have no further questions. The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.