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Good morning and welcome to the Magnolia Oil & Gas Third Quarter 2020 Earnings Release Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the call over to Brian Corales, Vice President, Investor Relations. Please go ahead.
Thank you, Gary, and good morning, everyone. Welcome to Magnolia Oil & Gas' Third Quarter 2020 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 on the conference call slide presentation with the supplemental data on our website. You can download Magnolia's third quarter 2020 earnings press release as well as the conference call slides from the Investor section of the company's website at www.magnoliaoilgas.com. I will now turn the call over to Mr. Steve Chazen.
Thank you, and thank you for joining us today. My comments this morning will begin with an overview of our business model, discussion of our plans and activities for the rest of the year, including an update on our Giddings development. I will conclude with a general outlook for 2021. Chris will review our third quarter results and our financial position. He will also provide additional guidance before taking your questions. Magnolia's business model, which focuses on spending approximately 60% of our EBITDAX on drilling and completing wells and generating meaningful consistent free cash flow while maintaining low levels of debt, remains unchanged. From our inception more than 2 years ago, this model continues to position us well by providing significant flexibility in how we choose to allocate our free cash flow.
Since the beginning of 2019, we have deployed approximately $165 million of cash towards small and mid-sized bolt-on oil and gas property acquisitions, repurchased more than 9 million shares of our stock, while building additional cash on our balance sheet. We ended the third quarter with nearly $150 million of cash, and we expect our cash balance to exceed $200 million by the end of the year. Turning to our operations. After not completing or bringing on any new wells online during the last 8 months, our third quarter total production of approximately 54,000 barrels of oil equivalent per day represents the trough period for production this year. We ended the third quarter with 8 DUCs in Giddings and 10 DUCs in the Karnes area, while running one rig operated in Giddings, which continues to drill development wells. We began completing wells at Giddings late in the third quarter and recently brought on our first 3-well pad. While still early, the wells on the recent Giddings pad are performing better than the average of the initial 14 wells in our core development area that we discussed with you last quarter. Of the 8 wells we plan to bring on during the fourth quarter, we expect 2 wells to be gassier, allowing us to take advantage of the recent increase in natural gas prices. Our total fourth quarter production is expected to grow 7% to 10% sequentially and production in Giddings is expected to grow by at least 20%, as a result the 8 DUCs being brought online. As the timing of these wells will be staggered throughout the quarter, the full impact will not be realized until the first quarter of next year.
Our optimism around the opportunity at Giddings continues as we experience additional confirmation around well performance and further improvement on well costs. Current average well costs are running about $6.5 million, which is down from $8.5 million during last year. Our operational efficiency improvements in Giddings over the past year have been substantial as we have focused our activity in our initial core area, transitioned to pad development, improved the -- improved the quality of our drilling crews. Drilling cost per lateral foot have declined nearly 55% and completion costs per lateral foot have decreased 50%, resulting in total well cost per lateral foot declining 45% compared to 2019 levels. These costs -- these include total costs for drilling, completion and associated facilities at Giddings. We expect to further -- to capture further efficiencies, as we execute our pad development, with total well costs falling towards $6 million next year. Before turning the call over to Chris, I want to provide some initial thoughts regarding our plan for 2021, putting a general framework for reinvesting our cash in the business and on the return of excess cash to the shareholders. Our plan is to continue to spend approximately 60% of our gross cash flow on drilling, completing programs as part of our organic program. We do not expect to alter this plan as it is a key characteristic of our business model and provides discipline within the organization.
Our At current product price -- prices, we plan to run one rig at Giddings in our development area. Our current drill times, improved efficiencies and lower costs, puts us on pace to drill approximately 20 wells in Giddings next year.
We expect to begin completing the DUCs in the Karnes area in the first half of 2021, and we currently anticipate a modest increase in non-operated Karnes activities throughout the year. This plan is expected to deliver moderate organic growth compared to our fourth quarter 2020 production levels. As I mentioned earlier, we expect our cash balance to exceed $200 million at the end of the year, and it is difficult to imagine that we need to carry much more than this at any given time.
Our overall balance strength is important to us. With only $400 million of bonded indebtedness and not due until 2026, paying down debt is not likely to add material value to our stock price. We will continue to look for small to mid-sized bolt-on oil and gas property acquisitions with similar characteristics to our existing asset base. Although we cannot be certain these will occur, we anticipate spending a sizable portion of our cash flows after capital and interest expense on acquisitions. Any acquisition with the need to be accretive to the value of our stock and prove our full-cycle cost metrics. Our increased confidence in the Giddings asset area makes us less likely that we will pursue a larger acquisition. Transactions are most likely to be of smaller bolt-on top -- type including -- could include producing properties or additional interest in our core areas. In the absence of accretive acquisitions, cash would be allocated to share repurchases. Bolt-on acquisitions and buying back our stock will improve our overall and per share metrics and should generate additional stock market value over time. We will continue to evaluate all cash flow allocation options, including dividends, and plan to provide more details around this as we roll out our full 2021 capital plan early next year. I'll now turn the call over to Chris.
Thank you, Steve, and good morning, everyone. As Steve mentioned, I plan to review some high-level points from the third quarter results, review our financial position and provide some guidance before turning it over for questions. Turning on Slide 4. Magnolia returned to profitability during the third quarter generating total adjusted net income of $15.6 million or $0.06 per diluted share. Our adjusted EBITDAX was $76 million in the third quarter with total drilling and completion capital costs of approximately $27 million. D&C capital represented 36% of our adjusted EBITDAX for the quarter and was better than our earlier guidance. We continue to expect our D&C capital spending to be approximately 60% of our full year 2020 adjusted EBITDAX, which is consistent with our strategy and business model.
We reported total production of 54,300 (sic) [ 54.3 million ] barrels of oil equivalent per day, 50% of which was oil. Third quarter volumes were negatively impacted by 2,000 BOE per day due to the delay of several non-operated wells in Karnes until the fourth quarter, as well as some unplanned downtime at a Karnes third-party processing facility. We have not completed any wells since February and did not bring on any new production during the third quarter. Oil prices stabilized during the third quarter after a very volatile and weak second quarter. Our third quarter oil and natural gas price realizations improved by 96% and 17%, respectively on a sequential basis. As a result of the recent sharp increase in natural gas prices, we took the opportunity to hedge 50,000 MMBTU per day of natural gas production, with just under half of our total daily natural gas volumes using costless collars with a weighted average floor price of $2.31 per MMBTU and a weighted average ceiling price of $3 per MMBTU from September 2020 through August of 2021. The hedge locks in a floor price of $2.31 per MMBTU that is well ahead of the price we realized thus far during 2020 while providing upside on half of our production volumes, should gas prices rise over $3. We view this hedge as more opportunistic and have no plans to hedge any of our oil volumes. Looking at the quarterly cash flow waterfall chart on Slide 5, we began the third quarter with $117 million of cash and generated $69 million of cash flow from operations before changes in marketing capital. Our D&C capital was $27 million during the quarter. We completed a small bolt-on acquisition in the quarter, most of which was an -- was an increase in working interest in our existing acreage. We repurchased 1.2 million shares of our common stock during the third quarter for $7 million, and have 6.8 million shares remaining under the existing repurchase authorization. We generated $46 million of free cash flow and our cash balance grew by $32 million during the period, ending the third quarter at $149 million.
At current product prices, we will continue to generate excess free cash flow after our capital outlays through the end of the year. Our $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's undrawn $450 million revolving credit facility was reaffirmed by our bank group last month, and our nearly $600 million of total liquidity is more than ample to execute our business plan. Our condensed balance sheet and liquidity as of September 30th are shown on Slides 6 and 7. Turning to guidance for the fourth quarter and shown on Slide 8, our total capital spending for drilling, completion and facilities is expected to be approximately 55% of our adjusted EBITDAX during the period. We exited the third quarter with 8 DUCs at Giddings, which we plan to complete and bring online during the fourth quarter. These well completions, combined with several non-op wells coming online in Karnes during the quarter, should provide sequential quarterly production growth of 7% to 10%. Production in Giddings should increase by at least 20%, as we bring on several multi-well pads. 2 of the 8 wells that we plan to bring online during the fourth quarter are expected to be gassier, allowing us to take advantage of higher gas prices.
As a result of these gassier wells, our gas production is expected to be a little higher proportionally during the fourth quarter. We plan to continue to operate one rig focused on drilling development wells in the Giddings initial core area.
Our oil realizations are expected to be about a $3 per barrel discount to MEH and around the same as the third quarter and in line with historical levels. We expect our cash balance to exceed $200 million at the end of the year. And as Steve noted, we do not need to build much cash at all beyond this level. Looking into 2021, we plan to invest approximately 60% of our adjusted EBITDAX on drilling and completing wells and consistent with the capital discipline that supported our business model since our inception. At current product prices, Magnolia plans to operate one rig focused on pad drilling in the Giddings initial core area. Based on current drilling times in Giddings, we estimate a one rig program at our current pace could drill approximately 20 wells per year, which should provide moderate volume growth compared to our expected fourth quarter production levels. In summary, Magnolia is financially well positioned with ample cash and liquidity. Further drilling efficiencies captured in Giddings should allow us to do more with less, providing us with excess cash to return to shareholders. We're now ready to take your questions.
[Operator Instructions] Our first question comes from Jeff Grampp with Northland.
Wanted to start maybe on Chris' last point doing more with less and what you guys got going on in Giddings in the well cost front. Do you guys think with seemingly good line of sight to get into a $6 million well, can that be sustainable longer term? And even if we do, at some point in time, get service companies clawing back some margins given that you guys probably still have some more efficiencies to gain, is that kind of a good longer-term development well cost or how should we think about continued efficiency gains?
Almost all the gain come -- came from drilling the wells quicker, which isn't a reason to cut from cutting the cost from the rig company. So I think the 20 wells for the year is also conservative. So we're continuing to improve our time. And so it might even be more than that. So I think we may be able to get it below $6 million. But I think $6 million in almost any -- any price environment that I could currently foresee or pray for is probably about right.
Okay. Great. And just on the results front, I know we're still early days on that recent 3-well pad, but anything you guys can point to as far as why those are doing better, is it geology or are you tweaking completions and doing optimization on that front or anything you can kind of conclude at this point?
Well, the average was a number of wells drilled over couple of years or so, maybe 2, 3 years. And so the average was reduced by some of the weaker wells that were drilled at one point or another that were done in a different way. So we expect that, that we'll be above that average. I mean, you could always drill a bad well, I guess. But we expect we'll be above that average going forward.
The next question is from Neal Dingmann with Truist Securities.
Steve, my question might be for you or maybe for Chris is just you guys continue to generate some nice free cash flow and you talked, I think, in the press release about some of the stock repurchase. My question with incremental free cash flow, do you see yourselves again just sort of building cash for that? You don't have a ton of debt. So I'm just wondering what sort of uses -- nearer-term uses of that between shareholder return or maybe even acquisitions?
So if we start -- so we spend 60% of the EBITDAX on drilling completing wells and equipping them. We roughly -- and then, we would hope to do some bolt-on acquisitions in either Giddings or Karnes. The market is sort of tight right now. So right now, you couldn't do much, I don't think. The next priority is likely to be share reduction, reducing the share count. And then we're considering a dividend, and we'll have more to say about that next year. The -- as far as paying down debt, it just doesn't make any sense. We have $400 million of debt. We've got $200 million of cash with -- I don't know, I guess, I could build to $400 million of cash, but I don't think that makes a lot of sense. In theory, we could start calling the debt next year. But I don't see where having zero debt is going to be real accretive to the shareholders, so I'd rather use the money for something else.
Great. Great details. And then just a follow-up. I know, earlier this year, you were pretty delivered on about drilling in Giddings and talking about the quicker sort of payback in Karnes here as we -- let's assume, again, that we exit the year around 40-ish again, knowing you don't have full details out for next year. How -- what are your thoughts about again continued with Giddings versus Karnes given the paybacks of the 2?
Well, the Giddings wells have a better cash return than a Karnes well. The Karnes well is fast -- comes back faster. So you have higher internal rates of return. But as far as money in the bank, the Giddings wells, over time, will generate more money for us and more present work for us. So in a low -- lower price environment, you can do that. In a Karnes well, basically you're drilling it, you're going to get $40 oil or whatever the oil -- current oil price is. In a Karnes well, it will be average over a few years. So in this current kind of environment, the Giddings well is more attractive. We had some Karnes wells drilled, some DUCs and depending on product prices, we make -- we'll probably complete those sometime in the first half of the year and some wells will probably be drilled next year. But we'll just have to see. The ideal environment for a Karnes well, even though the wells work just fine now, if you get $60 or $50 for the oil, and you get your payback down around 6 months, that's about right. So the locations aren't going away, I guess. And so with the -- the priority now is to build the lower decline Giddings results with the low finding cost. Finding costs are in the $6 area. And so I -- that kind of finding cost are -- all things considered in our program, right now that would be the -- I think the best use of the drilling money.
The next question is from Umang Choudhary with Goldman Sachs.
My first question is on -- just wanted to follow up on a previous question -- comment. If commodity prices do end up being higher and it's in the range of $50 to $60 oil, where would you deploy the incremental cash flows between Karnes and Giddings? The early results in Giddings is definitely favorable. And separately, if commodity prices do end up being higher, do you see the potential to spend less and deploy more cash towards acquisitions or share repurchase?
Well, the formula sort of fixes it. So if EBITDA is $400 million, we spend $240 million drilling. If EBITDA is $600 million, we spend $360 million drilling. We would -- the extra money, in that case, would probably mostly go to Karnes, where we can get a higher price environment, where we could get faster payback and reap the excellent economics there. And -- but we wouldn't increase the -- except by using the 60%, that's the only way to adjust the program. We're not going to adjust the program by going crazy and spending 80%, 90%. So if our EBITDA were $600 million, that would generate $240 million less the interest, so about $210 million for some kind of return to shareholders. Whether it's the share reduction or dividend, just depends on where we are at that time. So the answer is that the formula corrects itself for those sorts of things, within reason. $100 oil, I don't know what I would do exactly.
That makes sense. And I guess, my next question was on just Giddings area. Understand it's early days, and you still have your development plan ahead of you. I was wondering if you can provide any initial color on 2021 production growth and CapEx outlook for Giddings specifically based on your plans to allocate one rig in that area?
So -- you should expect one rig roughly for the whole year. We were going to do a rig in the half, but the efficiencies allowed us to do the same work with just one rig. We may put us -- a rig at somewhere in the middle of the year maybe to drill some exploration-type wells to see where we can expand. But that's sort of -- any excess money would go into Karnes drilling probably. I don't -- I'm not pressed to enlarge the program. Program, it's going to grow. I mean, the wells, you can look at the average we gave you for last quarter and even assume that. And again, they are -- they will be doing better than that. If we just assume that and where -- there is sort of 80% net revenue interest and 85%, 90% working interest typically. So you get some pretty impressive numbers of growth over the period. I mean, we said Giddings next quarter is going to [ earn ] at least 20%. And that's with partial results, really, not even a full quarter. We're going to put 11 wells on it or 8 this year and 3 more next year, as we continue to drill over the next quarter, 6, 3, 4 months. And that will clearly -- we've showed you 14, which are all the wells drilled. At the end of the first quarter, we are going to show you 25 wells. I don't know how much more data you need.
The next question is from Zach Parham with JPMorgan.
In the past you've talked about having some productive gassy acreage in Giddings, and you mentioned earlier in the call that 2 of the 8 Giddings wells that will be turned in line at 4Q will be gassier. Just given the move in the '21 strip to near $3, could you potentially drill some additional gassy wells next year? And I guess, just in general, can you talk -- sorry, go ahead.
That's the experiment. So we're going to see how these wells do. Our -- to be candid, every time we say it's going to be gassier, it turns out to be a great oil well. So we'll see if that works that way. But -- so -- even the gassy wells produce a few hundred barrels of -- a day of oil, black oil. So they're not just dependent on $3 gas. But $3 gas certainly helped. So we have a fair amount of gas prone acreage that could be developed in the $3 area. And -- but we're proceeding cautiously. Again, the acreage isn't going anywhere. But that's the purpose of drilling the 2 wells, to see what kind of results we'd get. We expect the results to be very strong.
Fair enough. Just a follow-up. On the recent Giddings completions on that 3-well pad, can you give us some detail on how those wells are spaced? And just any color on how you plan to space wells in the development program going forward?
They're extremely widely spaced at this time because we got unlimited acreage, and we don't really know. The goal in life is not to actually drill as many wells as possible but a few. So if I could put one well in the middle of Washington County and [ drilling ] the whole county, that would actually be the ideal outcome. So I mean, the goal is each well doesn't just accelerate the production, but also adds barrels. And if you drill too closely, you're accelerating the production and they interfere with each other. And I think that's a mistake the industry has made over the last few years. So we've got the -- in Giddings, we have enough -- plenty of acreage that we can space it extremely widely. And the wells' productivity, if you look at the curves, is pretty good. So there is no real reason to do tight spacing at this point or really any point. We'll see how these wells produce over the next 4 or 5 years and see how the curve flattens. But especially in a lower oil price environment, you really want to get the most you can out of your $6 million investment rather than do another one just to accelerate some production. We don't have the kind of issues some people have in trying to make banks happy with coverage ratios. So we can be fairly thoughtful about the development program, try not to waste too much money drilling wells.
The next question is from Lee Cooperman with Omega Family Office.
Yes. I don't think I'm saying anything that you don't understand because I think you're very sophisticated. But at the current strip, what would you look at as the net asset value of the company?
I don't know.
Well, you have an opinion, obviously.
I have a view. It's certainly a lot more than $4, $4, $5.
The reason I raised the question is basically the market has been extraordinarily harsh on energy companies. It basically says they have no future, okay? So every dollar you spend on drilling is being discounted in a significant way. And if the market is right on the -- the dim future for energy, we should basically not drill the money -- take the money drill, we should buyback our stock in aggressive fashion whenever it's showing a material discount to NAV. And that -- but I think you believe in that, but I just wanted to say in terms of the discussion on this call about allocation of capital, it seems to me repurchase of stock makes sense on only one scenario: that you're buying something back as materially more valuable than the price you're paying for it. And so -- and that's all, but I think you believe that, you understand that, and I just want to encourage you. I would reduce the drilling as long as the market is still disrespecting the energy industry.
But I agree with you, as you know. But the purpose -- as we -- Karnes is a known area. When somebody values that, we don't need to prove that, that works.
No, no.
The Giddings area is different. And so we did by -- by investing in the Giddings area, we're running under 60% [ just so you ] wanted to be. So -- and we -- we're now in the process of closing the share reduction program. But it's -- we're not doing it just to reduce the shares.
No, no, I think you're a smart guy, you're a large shareholder, you understand that if you buy back stock at the wrong price, you're screwing yourself. So the average analyst estimate is for -- price objective is $7.60 and we're twice the current price of the stock. Some people have it worth double digits. And I would say that if you think that the -- that those numbers are right, then the repurchase has got to be the best use of capital.
And it -- and it is, but -- but you also have to or note -- keep that $7.60 at this -- at this price, if that's the right number. The Giddings program is necessary to do that.
I got you. Well, I have a lot of confidence that you'll figure out. You're smarter than me.
Well, I wouldn't say that.
The next question is from Dun Mclntosh with Johnson Rice.
Steve, just one more question kind of on the recent 3-well batch at Giddings. Beyond spacing, what -- you talked about how the performance of those is exceeding what you saw in that first batch on the 70,000 acre core. Just wondering kind of if there is any differences, is it a sub-surface, is it a different landing zone, or if you tweak the completion recipe, I mean, just any color there would be helpful.
We continue to improve the efficiency, and there are some small tweaks. But the fundamental issue is when you compare the -- these wells with the average, there were some earlier less efficient wells, whatever you want to call them, in that average. But as we showed you, every well. So that's the large difference principally, and there are some tweaks to make it better. And we'll see how they perform over the next 3 or 4 months.
The next question is from Steven Dechert with KeyBanc.
Could you provide maybe some more color on what you're currently seeing in the M&A market, just hoping to get a better sense of what we should expect here in the near term, as far as an emphasis on...
There's really very little. It's -- people are afraid to buy for itself and that they have unrealistic expectations. Most of the companies' small assets we're looking at are -- have too much debt against them already, and so there is no net value. I think it will be a while before that's an active part of our business.
Okay. Great. And then can you just provide any like a rough dollar estimate for the 4Q CapEx number? I understand it's 55% of adjusted EBITDA. But just a rough number there would be great.
Well, I mean, you got to come up -- you got to come up the EBITDA and multiply that number out. That's simple. The only -- only reason we'd vary from that is if -- there is some -- I'm unable to manage it to be sort of right around there. But it -- it would be between 60 plus or minus 5% all the time. And we just don't really know exactly because these are small numbers to manage to.
Okay, great.
So you're saying -- you're accurate for $2 million and I'm not really that accurate.
This concludes our question-and-answer session. And the conference has also now concluded. Thank you for attending today's presentation. You may now disconnect.