Good day, and welcome to the Magnolia Oil & Gas second quarter 2020 earnings release and conference call. I would now like to turn the conference over to Brian Corales, Vice President of Investor Relations. Please go ahead, sir.
Thank you, Rocco, and good morning, everyone. Welcome to Magnolia Oil & Gas's second 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 two of the conference call slide presentation with the supplemental data on our website.
You can download Magnolia's second quarter 2020 earnings press release, as well as the conference call slides from the investor section of the company website at www.magnoliaoilgas.com. I will now turn the call over to Mr. Steve Chazen.
Good morning, and thank you for joining us today. My comments this morning will focus on our plans for the remainder of the year, including an update on the Giddings Field. Chris will review our second quarter results and financial position. He will also discuss our cost savings, where he's made some good early progress to better align our cost structure with the current product price environment. He will provide some additional guidance before we take your questions. Magnolia's business model remains unchanged, and we continue to focus our efforts on generating stock market value over time. The recent downturn has further solidified our strategy of running a focused business, maintaining low financial leverage, and spending within 60% of our cash flow, allowing us to generate consistent free cash flow.
Despite the challenging product price environment during the second quarter, specifically during the month of May, which was just awful, Magnolia's D&C capital was 68% of our adjusted EBITDAX. Based on our planned level of activity and using current product prices, we would expect our spending to be approximately 50% of EBITDAX during the second half of the year, and we remain committed to keeping within our 60% rule for the year. In response to the sharp decline in product prices earlier this year, we took actions to reduce activity and capital spending by dropping our operated rig in Karnes and curtailing any completion of additional wells throughout our assets. Although we have not completed any operated wells since February, we continue to run one operated rig in Giddings Field. We are currently drilling a multi-well pad in our early stage development area.
Our ultimate level of activity at Giddings through the remainder of this year will depend on product prices that would allow us to keep our spending around 60% of our EBITDAX for the year. At current product prices, we plan to start completing some of the DUCs in Giddings towards the end of the third quarter. We do not currently plan to complete any of the operated DUCs in the Karnes area during the remainder of the year. We believe that the pace of non-op activity in Karnes is currently picking up. In Karnes, we have more locations than DUCs, obviously. Because of the high initial production in a Karnes well, basically you're going to get $40 and $2 gas for it. I think there's plenty of time to reap that maybe next year.
In a Giddings well, we'll talk about here in a minute, the bulk of the production is spread over at least six months, so you get a more average oil price. I'd like to spend a few minutes specifically on our Giddings asset, and we would turn your attention to slide four in the conference call presentation. Since Magnolia's inception two years ago, most of our activity in Giddings was focused on gaining a better understanding of our 63,000 plus gross acre position through a steady exploration appraisal program. We would drill a well, then move the rig often many miles or sometimes several counties before drilling another of that well. This was not designed with the intention of forming an efficient development program, but rather was focused on an effort towards learning more about our acreage and establishing a model that would increase our rate of success.
Through this appraisal, we were able to outline a core area of approximately 70,000 acres where our results have been very good. While there are also other areas within our Giddings position that have shown very positive results, it is in this core area where we have the most data and well results. We currently have a total of 14 horizontal wells in this core acreage with at least 180 days of production. Results have been very strong, with an average well producing 1,374 barrels of oil equivalent a day for 180 days, with half the production stream as oil. At another level, the average well has produced nearly 250,000 barrels of oil equivalent in the first six months, with about half of that being oil. Production history of these well profiles demonstrates they are very different from a typical shale well.
The wells have typically reached peak production in the second 30 days and have a shallower production profile than our current wells that produce more oil over the life of the well. Evidence of lower rate of decline can be seen on slide four, as these wells have 30, 60, 90, and 180-day oil rates of 781 barrels a day, 783 barrels a day, and 677 barrels a day, respectively. Our most recent wells have exceeded these average rates. Our drilling activity this year in Giddings is focused on our early-stage development area and all with multi-well pads. Our first multi-well pad that we discussed last quarter, had an average well cost of about $7 million. This was well below the $8.5 million average cost that we experienced last year.
Our well costs should continue to decline towards $6 million per well as we see further efficiencies and gain more experience drilling on the acreage. As an example, on our most recent three-well pad that finished drilling in June, two of the wells set company record for per-foot drilling costs. Additionally, since we have started this early-stage development program, the average lateral well length has increased from about 5,000 feet, between 6,000 and 7,000 feet. Our total well costs have dropped but the average lateral length has increased. The strong well results in this early-stage development, combined with the recent improvement in product prices, has allowed us to drill additional pads in Giddings and expect to begin completing wells here before the end of the current quarter.
The shallower decline rates and lower well costs should improve our capital efficiency as we continue to pursue our development of the Giddings field. The driver in all of our activities is to keep our spending at around 60% of our cash flow. In summary, looking at 2021, if we assume $40 oil and $2 natural gas and maintain our guidance of 60% of our cash flow, we would have modest growth and generate significant free cash flow. I'll now turn the call over to Christopher Stavros.
Thank you, Steve, and good morning, everyone. As Steve mentioned, I plan to review some high-level points from the second quarter results, review our financial position, progress we've made on our cash costs and capital, and provide some guidance before turning it over for questions. Clearly, the largest driver of our second quarter financial results was the severe decline in benchmark oil prices and as a result of the sharp and swift drop in oil demand. This negative impact on our oil price realizations was especially evident during the month of May, for which a short period of time resulted in much wider than normal basin differentials. The short-term disconnect to benchmark prices seen during the second quarter has now abated, and we estimate our third quarter oil price realizations to be approximately a $3 per barrel discount to MEH, which is in line with historical differentials.
Looking at the quarterly cash flows waterfall chart on slide five, we began the second quarter with $146 million of cash and generated $33 million of cash flow from operations before changes in working capital. Our costs incurred for D&C capital were $28 million during the quarter. Working capital changes, including the changes associated with investing activities, resulted in a cash draw of $34 million, and we ended the quarter with a cash balance of approximately $117 million. Assuming we don't complete any oil and gas property acquisitions, and at current product prices, we expect our cash balance to build back to levels seen at the end of the first quarter. Turning to slide six, we reported total production of 64.1 thousand barrels of oil equivalent per day, 53% of which was oil, and toward the higher end of our guidance range.
Highlighting our production at Giddings, our oil production of 6.4 thousand barrels per day during the second quarter declined only 1.5% on a sequential basis, even though we did not bring on any new wells during the period. As Steve pointed out, this clearly demonstrates the shallower decline rate of our Giddings development wells and production stream in the field. Our adjusted EBITDAX was $40 million in the second quarter, with total drilling and completion capital costs of approximately $27 million. We were able to keep our D&C spending at 68% of our adjusted EBITDAX during the quarter, despite the headwinds from very weak product prices. Turning to costs on slide seven, the benefit of our cost reduction initiatives is evident in our second quarter results.
Our total adjusted cash costs in the second quarter, including interest expense and G&A, were $8.50 per BOE, a 29% decrease from the similar prior year period and an 18% sequential decline from the first quarter. We remain on track to achieve the $55 million of total operating cost savings we outlined last quarter, and we think we can exceed this amount through additional reductions in our LOE and G&A costs. As Steve noted, our costs for drilling and completing wells in Giddings continue to improve, and we expect our overall well costs to decline towards $6 million per well through further efficiency gains. Including our DD&A rate of $8.71 per BOE for the second quarter, which approximates our finding and development costs, our full-cycle costs during the second quarter were $17.21 per BOE, as shown on slide seven.
Using this cost structure and at current product prices, we expect to generate positive net income and earnings per share during the second half of the year. Our gross long-term debt of $400 million in senior notes, which mature in 2026, remained unchanged in the quarter. We do not expect to issue any new debt. We have approximately $570 million of liquidity, including an undrawn $450 million credit facility. Our condensed balance sheet and liquidity as of June 30 are shown on slides eight and nine. Turning to guidance for the third quarter, we continue to target our capital spending for drilling completions and related production equipment to be approximately 60% of our adjusted EBITDAX, which remains a core characteristic of our business model. We are currently drilling a multi-well pad in Giddings with our one operated rig.
Once this pad is finished, we will have 8 DUCs in Giddings. Further drilling will be dependent on product prices and our ability to keep our spending within 60% of our EBITDAX. We also have 10 DUCs in the Karnes area. We do not plan to complete any Karnes operated wells during the remainder of the year. While we did not complete any operated wells during the second quarter, we do expect to begin completing wells in Giddings towards the end of the third quarter. Production from these wells will be evident in the fourth quarter. With no wells turned in line during the current quarter, we estimate our third quarter production to be in the range of 55,000-58,000 BOE per day, with oil production in the range of 50%-52% of our overall volumes.
We expect the third quarter to be the trough period for this year in terms of our production. As we begin to bring on wells later this year, we expect our production levels for both the fourth quarter and the 2020 exit rate to exceed our production in the third quarter. At current product prices, we expect our D&C capital as a percent of our adjusted EBITDAX to decline during the second half of the year and be well below 60%. We expect to generate free cash flow for the remainder of the year, with our cash balance continuing to increase towards year-end. In summary, Magnolia is financially well-positioned with ample cash and liquidity. We are able to manage our activity levels in response to product price fluctuations and allowing us to allocate capital towards attractive opportunities. We're now ready to take your questions.
Thank you. We will now begin the question and answer session. Today's first question comes from Neal Dingmann with Truist Securities. Please go ahead.
Morning. Steve, my question is, thanks for the data on those first 14 Giddings development wells. Really, both my questions are on that topic, so maybe I'll just hit them both, and that's the first. Could you all speak to your plan to tackle Giddings as you potentially return to activity next year? Specifically, would you focus more on the 70,000 development acres, or will you start delineating some of the remaining massive position there? Really just secondly, you talked about in that development area, lowering cost, and I'm just wondering how quickly or, if you can lower the cost, how that development area would compete with Karnes. Thank you.
We'll start with the next year. Our current plan is to take one rig and continue drilling in the 70,000-acre piece. If we can manage it within the 60%, maybe we'll take a half a rig next year and use that to exploit some of the other places. It's all driven. The model drives off of how much cash flow you have. If oil prices were $40, you'd get one set of drilling activities. At $50, you get another. We would also expect at some point next year, we'd complete some of the Karnes wells. We also see that there'll be a pickup in the activity in Karnes from the non-op people, although we don't have any real numbers for that.
The costs will come down for sure because our days to drill a well have declined sharply in the last few months, and we're getting really good progress at that. It comes from drilling in the same area, you don't have to be quite as cautious as you were in some place three counties away. We're pretty confident in the declining well cost. The Karnes wells are shaped differently. You get a whole bunch of the production very quickly, and then you have a long period of modest production. The Karnes wells, you can see it, they all look sort of like this. You have pretty flat production. You start getting declines maybe three months afterwards. Decline is much shallower, the ultimate recoverable barrels will be significantly higher than a Karnes well.
You get your money back quicker in a Karnes well, but you get more barrels. If you're in a low price oil environment, and you think it's going to get better over time, you want to stretch your barrels over time rather than produce them all at once. If you start with the 60% and you say you're not going to, except for our inability to manage exactly, you're not going to exceed that. That's what guides the business. It actually creates the outcome. In a $100 oil environment or $80 environment, we'd probably switch to all Karnes drilling. I'm exaggerating the numbers slightly. You want to reap that $80 or whatever it is as quick as you can, get your money back real quick. In a low price environment, you want to stretch the production over time. As far as cost goes, they'll come down pretty nicely.
They're already really down.
Great details. Thanks, Steve.
Our next question today comes from Jeff Grampp with Northland Capital Markets. Please go ahead.
Morning, guys. Wanted to continue digging in on Giddings. Steve, I guess just kind of curious, I know that the 70,000 acres, you got 14 wells on it. Would you say that's all a decent degree de-risked at this point based on kind of the dispersion of those 14 wells? Then just kind of curious how much variability around that average you're seeing within those 14.
The answer is, I think they're not all bunched in one place, if that's the question. I think it pretty much tells us what's going on in the 70,000 acres. There's some variability. Most of the variability you might see in the results, you might have a mechanical problem or something like that, especially some of the earlier wells where we had some mechanical problems, you'll see more variation that probably exists. There's some variation, the current wells are I think as we've got the laterals longer, because we have more confidence in our ability not to mess up the well, we're getting better results. Generally speaking, I would view over time that these averages would get better, not worse.
Got it.
It's a lot of locations if you're running one rig. It'd be more entertaining if I were 40 rather than 75.
Still good stuff, though. Great. On the 2021 commentary that you gave in your prepared remarks, at 40 and two, you don't break the rule, you grow production. I guess, just wanted to clarify, is that the year-over-year growth, exit to exit growth? If I heard you right, Steve, it sounds like that contemplates a Giddings rig, some Karnes operated DUCs, and then some amount of Karnes non-op. Is that kind of the main inputs there?
Yeah. It'd be the growth from the fourth quarter, where we exit. That'll be up from the third quarter. That's sort of what we think. You'll have the non-op in Karnes, completion of the DUCs in Karnes, and then one or one and a half rigs in Giddings.
Okay. Got it.
At this [42], sort of. Chris showed it in one of the slides. The cash costs are not that great. You're generating a fairly wide cash margin here. More or less, the DD&A rate, after the write-down, is pretty much our finding cost. Maybe it's a little high to the finding cost, but it's sort of in that area. The financial statements, I think, pretty accurately reflect what's going on, at least for a little while. They don't usually over time. Right now they're reflecting pretty accurately what's going on.
Got it. Understood. I appreciate the details and the time, guys.
Our next question today comes from Stephen Decker with KeyBanc. Please go ahead.
Hey, just wanted to see if you guys are getting any AFE from other operators in Karnes?
Not much. We believe that they're doing some, but really not much. I can speculate as to why. If you looked at it may be that they have lease explorations or lease drilling commitments in other basins that they have assets in, which is what I guess is going on.
Got it. Okay, great. Thanks. That's it for me.
Thanks.
Our next question today comes from Guy Baber with Simmons Energy. Please go ahead.
Thank you all. Thanks for taking the time. I'm curious as to what is driving the shallow decline in the Giddings Field. Is that a function of ESPs, choke management, or just general reservoir quality?
No, it's general reservoir. If you think about a Giddings well compared to, say, a Karnes well. In Giddings, there are natural fractures, a lot of natural fractures. Historically, the vertical wells, they used seismic and they drilled looking for the fractures, which provided natural fracking, if you want to think of it that way. If you drill a horizontal well and you frack it, you'll have some of this Karnes-like effect of just fracturing the reservoir. You'll also open up some of these natural fractures, and they don't flow real quickly. It takes a while for the oil to move in there. It's a fundamentally different. Overall number. You've got some that looks like a typical frack well, but it's nothing to do with. We're not deliberately doing this. This is the way the wells really flow.
Got you. Perfect. I guess maybe this is a question for Chris. With the expectation of a growing cash balance towards the end of the year, your low cash burns on a go-forward basis, how should we think about the priority of cash outflows at some point? Is that priority one debt paydown? Is that hitting the A&D market? Maybe a mixture of those two and potentially even shareholder returns?
There's only so many things you can do. You can buy your shares, you can pay in the debt or call in some of the debt over time. We've prioritized over the last, certainly a couple of years, we've prioritized acquisitions, we've acquired a bunch of oil and gas properties that have been accretive to the model and accretive to the stock. If we can find some of those things, we'd like to do some of those things if they're accretive, and sort of PDP value at best, maybe two, three times cash flow. Otherwise, I'd let Steve talk to the dividend or something different.
Well, as far as the debt goes, we've only got $400 million of debt.
Right.
We've got six more years to go, and it's not exactly a big burden. Our coverage is certainly less than one, even in these prices. There's no reason to do anything with that, and there's no real gain in it, I don't think. Sort of a last resort. We'll just see where we are and see what happens with really two things. One is, will there be an opportunity in the A&D market to acquire things that fit in? We're not talking about going to some other basin. Things that fit in and give us where there's real synergies. You never really want to buy from somebody that knows more than you do about the asset. We'll want to be at least even with them.
There are some small things we can do in buying increased working interest in our current properties. The second thing is that we have bought stock in occasion, and that's still an option for us right now.
That's perfect. Thank you guys for the color, and I appreciate you taking the time.
Sure.
Ladies and gentlemen, as a reminder, if you would like to ask a question, please press star, then one. Today's next question comes from Nicholas Pope with Seaport Global. Please go ahead.
Morning, guys.
Morning.
I just wanted to talk a little bit more, topic of the day, I guess, with Giddings. How many of the wells you are looking at in that core area has Magnolia drilled and completed versus what was in place in those numbers upon the acquisition of the asset?
How many? All 14 are ours.
Oh, they're all yours?
Yeah.
Got it. You hit on the variance that we see, and I think this is a comfort with just a lot of investors with these chalk plays and the variability of performance. I guess, you've seen what performance has been to date. When you start to project the drilling program in Giddings, what are the Magnolia expectations of variance on well performance in that core area going forward?
Well, aside from a mechanical problem, or some kind of drilling screw-up, the wells are within a modest amount. There are some considerably better, that's true.
Those are the ones that jump out on the screen, I guess, is the huge wells that you guys have done there.
We didn't cherry-pick the wells.
These are all the wells.
these are all that we have 180 days of production.
Yeah. That's all there is.
All right.
There really isn't anybody else that drills in this area because we have all the acreage. That's all there is. We didn't pick any of it. That's what it is, if you want to do a standard deviation, you can do that, but some of the weaker wells are basically ones that had some mechanical problems. Nothing fundamental. Not to say that if you drill 50 of these, that there won't be some near the edge. As we might try to expand the 70,000 acres to 80,000 or something like that, you could run into an edge play, I suppose. As far as drilling within the sort of current boundaries, this is what you're going to get. You will get some variance, there's no question about that. We've shown you all the data there is. We don't have any more.
I appreciate that. I just wanted to hear you guys talk about it. That makes sense. Thank you. That's all I had.
Thanks.
Ladies and gentlemen, this concludes the question and answer session. I'd like to turn the conference back over to the management team for any final remarks.
Thank you for participating in the call. We'll talk to you next quarter.
Thank you. This concludes today's conference call. We thank you all for attending today's presentation. You may now disconnect your lines and have a wonderful day.