Good day, and welcome to the Magnolia Oil and Gas First Quarter 2020 Earnings Release and Conference Call. Today, all participants will be in a listen only mode. After today's presentation, there will be an opportunity to ask questions. Please note that today's event is being recorded. At this time, I would like to turn the call over to Brian Corrales.
Please proceed.
Thank you, Chris, and good morning, everyone. Welcome to Magnolia Oil and Gas' Q1 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 ks 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 Q1 2020 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, Brian. Good morning, and thank you for joining us today. My comments will focus primarily on how Magnolia is positioned to navigate the weak product price environment and current downturn as well as providing an update on some of our recent activity in the Giddings field. Chris will review some of the details quarter results, our current financial position and provide some broad guidance before we take your questions. Magnolia's strategy and business model has not changed.
The quality of our assets and the characteristics of our business model has served us well since our inception and continue to provide us with a strong foundation for the long term. Our business model predicated on low financial leverage is designed to withstand periods of weak product prices. We exited the quarter with $146,000,000 of cash in our balance sheet, $450,000,000 of undrawn revolver and $400,000,000 of debt, which does not mature until 2026. Our targeted annual capital spending for drilling and completing wells remains at 60% of our adjusted EBITDAX and we generated $23,000,000 of free cash flow during the Q1. We remain focused on the things that are in our control.
Most of our current planned capital spending and activity for the year occurred in the Q1. The current weak product prices do not justify bringing new wells online. As a result, our capital spending expect to see a sharp decline for the remainder of the year. We currently plan to drill a few additional wells in Giddings, although we don't expect to complete any wells until the Q4 or until we have some better clarity around product prices. Our spending for drilling and completions expect to be less than an aggregate for the remainder of the year than we spent in the Q1.
We've also taken steps to reduce our operating expenses and overhead in order to better align our cost structure with the environment. Corporate wide salaries have been reduced by 10%. Excluding any additional savings from our capital program, we expect to realize at least $55,000,000 improvement in our 2020 cash operating costs and G and A compared with our original plan. Fortunately, savings should be realized in the second quarter and more fully captured in the second half of the year. Our cost reduction initiatives remain ongoing an ongoing effort throughout the remainder of the year.
As a company, we have run a focused business. As a result, narrow focused business really. And as a result, we can optimize our production on each well. Sometimes that's an advantage, sometimes not. But right now, this allows us this focus allows us on generating free cash flow at very low product price in a very low product price environment and allows us to manage our business more effectively.
We can share resources more easily because our business is so narrow. Our underlying business and assets performed better than expected during the first quarter, driven by strong production results from both our Karnes and Giddings assets. With no significant financial or operational restrictions or obligations, our business model provides us with the flexibility to adjust our activity levels very quickly in response to changes in product prices. For example, some portion of our acreage in Giddings' capability produced high flow rate natural gas wells. While we have not focused on this acreage during the last 2 years, we would consider allocating some capital to this acreage should gas prices improve later this year.
We expect that these wells to be fully competitive with Haynesville wells. In Giddings, we brought 4 new wells online during the Q1 with an average 60 day oil production rate of 800 barrels a day per well. 2 of these wells were drilled from the same pad to replicate early stage development. These two wells had 90 day average rates of 1,000 barrels of oil a day. The cost of these wells were more than 20% lower than the 2019 average cost in Giddings despite having lateral lengths that were approximately 25% longer.
Our recent positive results in Giddings increased our confidence on the future development opportunity in the field with the potential for several 100 drilling locations. Giddings would be the 1st area where we would bring back a rig and complete wells as product prices recover. We continue to evaluate several small to midsize bolt on and oil and gas property acquisitions opportunities. While the M and A market has been stagnant so far this year due to the weakness in volatility in product prices, there are some signs of the process beginning to loosen. We expect opportunities to expand our business will appear later this year once market conditions clarify.
As always, we will ensure that anything that is done is accretive to our business and is clearly positive for our shareholders. To summarize, Magnolia's financial position remains strong and the balance sheet provides us with a competitive advantage. Our current cash balance would allow us to fund all remaining capital spending for this year well as our cash overhead and our interest payments at least for the remainder of 2020 before considering any revenue generated by our production. Our free cash flow generating business model continues to provide us optionality to allocate capital towards opportunity that are most beneficial to our shareholders. I'd now like to turn the call over to Chris Stavros.
Thank you, Steve, and good morning, everyone. As As Steve mentioned, I plan to review some high level points from the Q1, speak to some more detail around our cost savings initiatives and provide some guidance for the 2nd quarter before turning it over for questions. Looking at our quarterly cash flow summary on Slide 5 of the conference call presentation posted on our website, we generated $135,000,000 of cash flow from operations and our total cash outlays associated with drilling and completing wells was $94,000,000 during the quarter. Free cash flow after changes in working capital and capital spending was $23,000,000 during the Q1 we've generated free cash in every quarter since the inception of the company. We repurchased 1,000,000 Magnolia shares for approximately $7,000,000 and closed on a bolt on acquisition of primarily non op oil and gas properties in the Karnes area for approximately $70,000,000 The acquisition closed in the second half of the first quarter and contributed less than 800 BOE per day of production to the quarter.
And we ended the Q1 with $146,000,000 of cash on the balance sheet. Reiterating Steve's comment regarding our cash position, we currently have sufficient cash on hand to fund our remaining planned capital expenditures, cash overhead and interest at least through the remainder of the year and carry us into 2021 before consideration of the revenue generated from our oil and gas production. Turning to costs on Slide 6, our total cash operating costs in the Q1 including G and A was $9.42 per BOE, a 14% decrease from the prior year period. Our cash operating margins after all cash costs were nearly $20 per BOE during the Q1. Adjusted EBITDAX was $124,000,000 in the Q1 with total drilling and completion costs of approximately $101,000,000 or 81 of EBITDAX and lower than our guidance.
Looking at Slide 7 of the presentation, total production from the company averaged 68,400 BOE per day during the Q1, a 10% increase compared to last year's Q1 and approximately the same as volumes in the Q4 of 20 19. Well production represented about 55% of our total volumes during the Q1. Production exceeded our earlier guidance and as Steve mentioned our stronger volumes were due to better than expected well performance from both our Karnes and Giddings Field assets. Our gross long term debt of $400,000,000 in senior notes remains unchanged in the quarter and we do not expect to issue any new debt. We have approximately $600,000,000 of liquidity including an undrawn $450,000,000 credit facility.
Our condensed balance sheet and liquidity as of March 31 are shown on Slides 89. To summarize, Magnolia is financially well positioned to manage through the current challenging period of weak product crisis. As part of our cost reduction initiatives in response to much weaker product prices, we expect to achieve approximately $55,000,000 of savings in our 2020 cash cost compared to our original plan. The improvement in costs are largely comprised of savings from field level operating expenses, gathering and transportation, general administrative expenses and contractor fees. Large majority of the savings come from payroll and other people related costs and equipment optimization in the field.
These savings are part of our initial cost reduction efforts and we expect to see more over time. And this is also separate and apart from the cost reductions we expect to realize from our capital program. While a portion of the cost improvements should be evident in the Q2, the full benefit of the savings is expected to be realized during the second half of the year. In terms of our drilling and completion costs, as we started the year, we expect that our average well cost to decline about 10% compared to 2019. In Giddings, drilling and completion costs on a multi well pad we drilled have already seen a 20% reduction despite the wells having lateral lengths that are 25% longer.
When we continue our early stage development at Giddings, we should continue to capture additional efficiencies, which would further reduce our overall well costs. Turning to some additional guidance, we continue to target our capital spending for drilling, completions and related production equipment to be approximately 60% of our adjusted EBITDAX. This is a core characteristic of our business model, which remains unchanged. We released our Karnes operated rig in April and are currently operating 1 rig at our getting sealed asset. We've ceased all well completion activity for the time being due to very weak product prices and expect to have several more drilled and uncompleted wells by the end of the year compared to our original plan.
This reduction activity will be reflected in much lower capital with our total spending for the year below our outlays during the Q1. We currently expect that our full year 2020 capital to be less than half of last year's spending level. Magnolia operates approximately 75% of its total production volumes. We currently expect to shut in less than 5% of our operated production during the month of May and a smaller amount for June as a result of very weak product prices. This includes a mix of operated production in both Karnes and Giddings.
Due to these curtailments, we currently expect our total second quarter production to be in the range of 62,000 to 65,000 BOE per day. We estimate our oil production to be approximately 52% to 54% of our total volumes. Looking at our 2nd quarter expenses, unit cash operating costs including G and A are expected to decline about 5% from 1st quarter levels and as a direct result of the cost reduction initiatives we have implemented. Finally, as we disclosed in our press release, we incurred a $1,900,000,000 non cash pre tax asset impairment due to significant weakness in product prices. As a result of the impairment, we estimate our DD and A rate should decline approximately to approximately $9 per BOE for the remainder of the year.
In summary, Magnolia is properly positioned to endure the current downturn in product prices. Our significant cash balance should help us withstand the intermediate term volatility and allowing us to take advantage of potential attractive opportunities to further strengthen the company. We're now ready to take your questions.
We will now begin the question and answer Today's first question comes from Leo Mariano with KeyBanc. Please proceed.
Hey, guys. Just wanted to follow-up a little bit on activity levels here. Just in terms of the rig in Giddings, I'm not sure if that's still contracted through a certain time. And then I guess if prices stay low, maybe that rolls off. So I was hoping you could address that.
And I also wanted to see what type of oil prices you guys might need to start fracking wells again. You mentioned there's a possibility in the Q4. So what would you kind of see for that to happen?
So I think we start with the rig. The rig is under contract, but we've made arrangements with the contractor. So we can extend that period when we come back next year or whatever we can do that. But I think we're it's so cheap to drill and it isn't that much money. Completion is a different story, but too so deep to drill that we decided to go ahead and drill.
And this is a 3 well pad that we're drilling. So these are pad drilling that we'll bring on maybe in the Q4, but probably next year. I don't really know what the price that we'd go back in. Mike, the margins are so wide on these wells once they're up and running. You could do almost anything as long as the completion costs were reasonable.
So I'm going to guess somewhere in the 30s whether it's 30 or 35 or some other number, I don't know. But somewhere in that area, we start completing wells. But probably not before that and probably not until we had more confidence in where the economy is headed. So somewhere in that area, we should be if you take our operating costs that Chris talked about and G and A and all that other stuff and take the $9 DD and A rate, somewhere in that 30s we'll start to report earnings. So that since I'm sort of an old fashioned investor, that's sort of what I'm looking for.
Okay. That's very helpful for sure. And I guess just in terms of the recent drilling at Giddings, it looks like that 2 well pad a rousing success. You guys mentioned potential for several 100 locations. Just wanted to dive into that a little bit more.
Do you guys feel like that the drilling program at this point has identified some key sweet spots throughout Giddings that can be the target of future pad development here? And do you think that several 100 locations is a pretty high probability at this point in time? What can you kind of tell us about the progress there?
Well, sample size is 20 some wells. So and we experimented with different areas. In this one area, I think we've got pretty high confidence. The other areas we've had some good results, but not many wells. So I think the pad drilling will work in this good area.
And I don't really know how many locations there are given the current base of drilling, the locations will significantly outlast me. So I'm not really concerned about counting up locations, but we should have a very profitable business. Remember, they don't decline. They produce a lot of oil, a lot of product over their lives. If the costs which I think we can get down to around $6,000,000 a well, it's 50% more say than a Karnes well with more than twice as much production, maybe 3 times the production with a lower decline.
We'll continue working on Karnes, of course, but I think this will provide a balance to the business. And if you don't know about product prices, you go for these longer live things where the money you might not get the best price today. But if you have confidence over 2 or 3 years, you'll do a lot better in the Giddings wells than you will in Karnes well. Karnes well as we look at it, product prices are high, you drill a hell out of Karnes because you got real short paybacks. But in the Giddings is for a longer a longer play where you're less confident about oil price.
I guess that's how I'm thinking about it at least today.
I think that makes a lot of sense.
And just lastly on M and A, you sort of talked about that potentially starting to maybe loosen up a little bit here. You had the one deal in the Q1. I'm assuming that was kind of a legacy deal negotiated towards the end of the year that sort of closed here. Maybe just talk more about what you're seeing on the M and A side and just kind of how you prioritize free cash flow from here on out?
Well, everything's got to compete with Giddings or Karnes. So if the money is better spent completing Giddings or Karnes wells, that's where the money will go. We don't there's really nothing much to buy and get. So there's really nothing there that does upgrade interest. And we have so much, there might be a few 100 acres here and there, but fundamentally nothing very large there.
And most of the stuff is really in a different part of the basin that might be available, not all that interesting. Maybe we pay 1 or 2 times cash flow, dollars 30 oil, some exorbitant price like that. So if you go to Karnes, there's always small pieces around. And as some of these private equity things unwind, we might find some there. But we're not going to be big payers there because right now we've got a pretty long runway.
I don't view that in this environment or the environment I perceive for the next couple of years, drilling locations are going to be rare and special. I think there's a lot of locations around and I'm not really concerned about locations right now. I'm concerned about cash flow generating.
Okay, great. Thank you.
Thanks.
The next question comes from Jeff Grampp with Northland. Please proceed.
Good morning, guys. Steve, I thought your comment on maybe gas making some sense in Giddings get after was interesting. So I was hoping to dive into that more. Can you give us a sense, I'm sure the gas price has to make sense relative to the oil
at maybe 'twenty one strip prices as some
observable number. But just at maybe 'twenty one strip prices as some observable number, but just trying to, I guess, get a sense of what that inflection point is to where that could be interesting.
The wells would work now to be honest, but we probably wouldn't do anything with it until we got closer to $3 for gas. And because they also produce some liquids. They aren't just they aren't dry gas wells. They got about 20% liquids. So NGL prices, which are in the toilet right now, and they have produced some oil.
So a little got some of that to it. But I think it's probably closer to $3 than $2 We could drill a Giddings oil well even at $30 that easier and more attractively than gas wells, but we could drill a lot of gas wells, high volume gas wells. If you want to inflate our BOEs, that would be the way.
All right, understood. And on the cost cuts at Giddings, the 20% number that you guys referenced, can you kind of maybe split that out in terms of maybe some efficiencies that you're seeing from doing pad development that's driving that versus maybe just generic kind of oilfield service company type of cost?
It's not driven by oilfield service guys. You get a little better crews now than you had before because they've read it out some of their crews. But it's driven by the fact the wells are drilling faster because we know more about it. It's actually driven by knowledge rather than anything else. We're drilling the wells faster.
We know how to complete it. We've gone through it. Drilling the wells faster. We know how to complete it. We've gone through an experimental phase, if you want to think of it that way.
It's principally driven by knowing what we're doing as opposed to trying to guessing what you're doing and trying to learn. So I think we'll be down another 10% or so at some point here once we start completing the wells. So I think we're really in the early days of this. But again, it's driven by knowing having a better feel for what you're doing than we did maybe a year ago.
Got it. Sounds good. I appreciate the time.
Thanks.
The next question comes from Will Thompson with Barclays. Please proceed.
Hey, good morning, everyone. Steve,
what would cause you
to be more proactive about shutting in production? And maybe can you remind us what your market arrangements look like and whether you expect any impact from the CMA role? You mentioned reducing GP and T costs and that $55 of cash savings. Correct me
if I'm wrong, but I
believe a lot of the getting barrels are moving by truck. Just help us understand where the opportunity is?
I sort of take a naive view to Wells. We can't influence the product price by whatever we do. Exxon might be able to or Oxy or somebody might be able to influence the product price. And a lot of them have long transportation. They got to transport from the Permian to wherever.
We basically sell locally. So some of the Giddings wells are trucked, but that's in the cost. And ultimately, we'll deal with that. There's a pipeline that we could oil pipeline that we could acquire with one there that we could refurbish if you want to think of it that way once we get going again. So I'm not there's more money there to be had down the road, not right now, down the road.
Trucking is easier. We're unless if the well contributes to free cash, in a predictable way, we're going to produce. We're not going to shut in for because to speculate on oil price again, I figure I got a lot of locations. I don't need to do that. And I don't really have a way of predicting oil prices.
I could prove that to you if I had to. And so I think you just got to you got to take you got to run this like a real business not some wacky oil business. And somebody other people have different objectives. They may have different cost structure. They may have take or pay requirements on the pipe.
We don't have any of that. We just don't have anything we have to do. We could shut everything in I suppose. But I don't know what the gain would be in that. The production when it comes back, the period that you're shut in doesn't it's not like putting oil in a tank and then just moving the tank.
That recovery is spread over several years. So I just soon have the cash now and can work with it in this depressed environment. We'll generate free cash. May is going to be ugly for sure. But we'll survive May and June looks a little better and June will be better.
So I'm not really it's just not the same business model that somebody else might have that might be 5 or 6 basins and it's got a lot of overhead and has maybe commitments to ship in different basins. A lot of companies have more complexity than we have. So this is sort of a simple business. We can generate well generates free cash. We'll run the well.
If not, we won't. And we look at that every day on each well. So it's a pretty straightforward calculation. It would be just like running a private business as opposed to trying to optimize something for public business. I'm not really worried about what the we can make lots more production next year if we need it.
But obviously even if we didn't produce anything, we're probably not going to move the product price.
Okay. That's helpful color. And then in terms of giddings, where are you in terms of completion designs, profit intensity, etcetera? Just trying to understand, are you still tinkering with well design? And I know one challenge in getting is that well costs getting well costs down was that you weren't moving to larger pad development just given that you're still in delineation mode.
You mentioned $6,000,000 is the opportunity. Does that include moving to larger pad development?
It's what a pad a small pad would be about $6,000,000 I don't view that as the ultimate objective. That's just what's obviously visible now. Once you get there, you move the goalposts. I mean, you got to be able to you got to decide that you're going to that this business is not an $80 a barrel oil business or a $70 business or a $60 business or a $50 business. It's a business that has got to work at much lower prices.
It's nice if it goes up. But I think right now there's a lot of demand destruction. It's going to take a while to recover. Oil guys are always optimistic that next quarter will be better and maybe a little better. But I don't think you should you can no longer run your business as if oil is going to be $65 forever.
And that means less debt, less interest expense, less overhead and tighter control on how you spend your money. You need to spend money on stuff that works in the 30s.
Seems like some of your peers are learning the hard way.
Just on
the follow-up, just on terms of completion designer, can you just give us
a sense of that? There really isn't much change. That isn't we monkeyed with this a lot. I'm sure it will be tweaked. But right now, we'll get it down to the $6,000,000 run rate and then we'll look at it again and see if something we can do to take another 10% out.
So right now we're if you can produce 1,000 barrel of oil a day wells for 90 days or longer and with a much lower decline than Karnes, completion design is probably okay for now.
Our next question comes from Neal Dingmann with SunTrust. Please proceed.
Steve, just maybe add on to what you were just saying on the Giddings, if you just add a couple more detail. I know not long ago you'd mentioned, I think you and I were talking, you talked about just on cost, on services, obviously tough business right now. And I'm just wondering for you or Chris and maybe in some of the your estimates or forecast forward, are you anticipating that part of that $6,000,000,000 cost that costs continue to fall or maybe just talk about what you're anticipating on that?
No. We're not talking I never feel sorry for service company. So I always think they could cut more and to work for less. Some they cut their CEO pay down the mine. I already tried that.
I already did that experiment some other place. And anyway, we're not counting on that. I think they're pretty close. Where you gain to be honest in the service companies is not what they charge per hour or per day or whatever, it's the quality of the crews. If you got if they recruit their crews at Huntsville, then you're going to get Huntsville style outcomes.
If these are experienced people who've been around and these are the people who are trying to protect, you're going to really get good outcomes. It's much more about the quality of the crews than about exactly what they charge. We pay a little more frankly for the better crews because all they got to be is a day and a half better and they are. So the issue with service companies generally is that as the business expands, the crews get lousier and you get worse results and so your costs are. Isn't that the service companies get rich because there's too much competition, but not that they don't want to get rich.
But I really think that's the key element that We are counting on that the crews stay good quality crews. But as far as actual cost reductions, we're not looking at that. I don't think there's a lot more there to be honest.
Okay. No, that's fair point. And then you touched on this, but I'm just kind of curious your philosophy. In down cycles like this, when you think about shut ins and drilling and completion suspensions and DUCs, I'm just wondering, when you put all that together, I mean, Steve, I mean, you always say it doesn't make sense to drill obviously in these kind of prices, but I'm just wondering anything else that I'm just wondering how you you've shut in a little bit. You've had obviously you're going to have much more major D and C suspensions.
I'm just wondering could you just talk about kind of given your past how you view for
We've only shut in what doesn't make sense. We're not shutting in to manage production or something. Some other people are clearly managing something else. I don't know what. But and about a quarter of production is outside operated.
They don't actually communicate with us. The only reason we know what's going on is we see the run rate or we read the press releases. So you don't really know what the motivation is. So again, a large company may think it's managing prices, may have some contracts or something. You don't really know what's going on.
On the drilling, we had a rig contract. We negotiated with a contractor. And so we got pretty cheap prices for drilling some wells. It's where we would drill next anyway. And so we'll drill those wells.
As far as completions go, we'll wait until we've got more clarity on product prices. But I'm guessing that's somewhere in the 30s. And the rest of and then in Karnes, I assume that the 3rd party operators, the outside operators will pick up at some point there, I guess. So I don't like building docks, but we are going to build some. And mostly because I got pretty good confidence that oil will get to somewhere in the 30s.
If I thought this was stuff that needed 50s, I wouldn't build any docks.
Thanks. Really appreciate the time. Thank you.
Sure.
The next question comes from Jeffrey Campbell with Tuohy Brothers. Please proceed.
Good morning. Thanks for taking my question. Steve, regarding the extra giddings locations that were identified in the preamble, I was wondering, does this center mainly on the recent success area? Or was this kind of a broader number referring to? I
appraisal you've done?
No, it's centered on where we've recent not so recent, but where we're doing the development drilling.
Okay, great. Thank you. In most every E and P says it's aligning how far out into the future are you looking to make these judgments?
Yes. The G and A is not where we want it to be. It needs to be reduced sharply. So we're working on a plan to reduce it materially from here.
Okay. Thanks.
You might remember that we have a contract with Enervest to for some of the back office and some of the well management and that sort of thing. And so that might be a target for reduction.
Okay. Thanks. And that actually kind of leads to my last question, which is, is there any sense when you're at the point in the future when you can expand your Giddings program again that you might develop an in house capability for those assets? Or are you likely to keep using something like current operating arrangement?
No. We'll use our own. It doesn't we could do that now.
Okay. Thank you.
The next question comes from Biju Perincheril with Susquehanna. Please proceed.
Good morning, all. Thanks for taking my question. Thinking about when you were resuming activities, how we should think about the Karnes area, not necessarily looking for a price, but when you go back to work, should I think about the first couple of rigs going to Giddings and only then going to picking up activities in Karnes?
Something like that. 1st rig that 1st rig that and the 1st completion crew will Giddings. We'll probably put a completion crew in Karnes at similar time because we have some docks there. As far as drilling, I would think the next drilling would be in Giddings. I don't I just don't know if oil is $35 it would probably be Giddings.
If oil is $45 we'd probably put a rig into Karnes. But it just depends on how certain I am over time about the direction of prices. If you got a high degree if you think it's still why it's volatile, volatile being bad volatile, not up volatile, then you probably would you'd spend more at Giddings and less at Karnes. If you thought it was if you had a spike in prices, we might drill a lot of carbon wells. The payout is real quick.
You produce 4,000 barrel a day wells or like that and you get your money back real quick. And then you've got a long low cost stream after that. So it's a good well. It's a good well in a where you can reap a lot of money upfront, get your money back real quick.
That's very helpful. And my follow-up was on the gas optionality you talked about. Those wells are those much deeper? Is there an appreciable difference in the well cost than you expect from the gas
wells versus? They're somewhat more expensive. But of course, we haven't drilled 1 and we're not using some of the stuff we've learned since. So I don't really know what it would run us. If they're somewhat more expensive, I want to guess it's a $7,000,000 well or $8,000,000 well, but not a $10,000,000 well.
But that's just a guess.
That's helpful. Thank you.
Our next question comes from Kashy Harrison with Simmons Energy. Please proceed.
Good morning all and thanks for taking my questions. So Chris, maybe one for you. I was wondering how we should think about just the 2020 exit rate based on your current expectations and if you have a sense of how much capital or activity you would need to hold that production flat at least through 2021?
We just don't know right now. I mean, we sort of see out into the current period, but beyond that. But what is encouraging is what you're seeing out of Giddings and the decline rate. So it's obviously it's a more efficient
other gas production that we
have has certainly helped the sort of the other gas production that we have has certainly helped the decline rate and the efficiency of the production overall. But I can't speak to an exit rate right now.
We're lucky we could do next month on our exit rate. So I figured being able to figure June was a major victory.
All right, fair enough. And then Steve, maybe one for you. You talked a bit earlier about just needing to adjust the business to whatever price is right in front of you. And so I was just wondering how we should think about or maybe it doesn't evolve, but how you think about inventory depth if you are if we in fact in this $35, $40, $45 world for quite a bit of time? How many locations do you lose or is that getting inventory that you talked about in the past still pretty much unchanged?
Inventory that you've talked about in the past still pretty much unchanged?
And by the economic inventory? Yes. The giddings stuff, we've taken care of the risking of that. So we've that sort of works in this $35 sort of environment. It might be more locations, dollars 60 environment.
Karnes, I think it works in the same general area. So we never had a lot of high wells that required $55 or $60 maybe a few marginal wells in Karnes that were out of the main fairway. We just never had a lot of inventory that was sensitive to the product price of reasonable product price changes. So that's why we only have a small reduction in our shut in wells because all sort of work if you have a workforce that's focused in just a narrow area, you get a lot of flexibility. And somebody in 5 basins just doesn't have that kind of flexibility.
And this business is inherently more costly. This runs sort of like you would run if it was your money rather than some third party's money.
Makes sense. That's helpful. And then maybe just a minor housekeeping question for me. I was just you talked about the lateral length on these Giddings wells being I think 20%, 25% longer than last year. I was just curious what that lateral length was for these pads and if that's a good idea of how you think about the long term lateral length of the wells you'd be targeting in Giddings or if you might get a little bit longer over time?
6,000 roughly is what we're doing now. We were below 5,000,000 sort of before as you get long, we don't have a lot of times some places you're limited by your leases. We don't have that kind of constraint. So but we probably wouldn't experiment with we would experiment in a higher price environment to see if it worked rather than trying to stretch the model a little bit and run unnecessary risks right now.
Got it. Makes sense. All right. Thank you.
Thanks.
Our next question comes from Brian Downey with Citigroup. Please proceed.
Good morning. Thanks for taking the questions. Chris, Steve mentioned earlier that the industry needs less interest, less debt. Obviously, no credit facility balances. As you're thinking about capital allocation, Magnolia Senior notes have recently been trading around $0.80 to $0.85 on the dollar, at least that's what we see on the screens.
Is that something you've considered using cash on hand or credit facility availability to repurchase any of those notes below par? Would there I guess, would there be any limitations or difficulties if you wanted to do that strategy in the open market? And could that be part of the Magnolia Capital Allocation Suite?
Probably not right now. I talk about limitations. I mean, I'm not sure how much of that you could how liquid it is or how much of that you could soak up, but probably not enough to make a difference, frankly.
The other part of it is, it's got we've got 5 more years on maturity.
Yes. 6 actually.
So you got a while to go here and give up that optionality to for a very small gain. I just view it our interest expense is $24,000,000 6 times $400,000,000 is $24,000,000 a year. So if you bought it for if you could buy it all for $0.80 to the dollar, so now you're down to $0.20 you save hardly anything. It just isn't worth it for the fact you don't have to worry about paying it back for a while. So a lot of people have pretty wide discounts.
Some guys are 60% discount, 70% discount and large sums. There sort of starts to make sense. Just doesn't make a lot of sense. And when we look at it, buying $1,000,000 at $0.15 at $0.85 would be challenging. So I don't I sort of like the optionality of the debt out there so
far. All right. That's helpful. Thanks for taking it. Thanks.
Our next question comes from Irene Haas with Imperial Capital. Please proceed.
Yes. The question I have for you is your crude price realization. Can we have a little color as to as we go through this year, what the premium would be versus WTI? I assume that you don't probably have any gravity issue. The second question is what Steve said earlier.
You said there's lots of demand destruction. It will take time to recover. Steve, can you quantify what is the time that would be required?
The product price, Chris can talk about product price, but the product price is you got the disaster of May. And then it's looking better in June. You really have a hard time coming up with a product price that you have any confidence in for this quarter. All of a sudden, let's say, the price of WTI goes to minus $55 just screws up the whole calculation because it's the average over the month. And so anybody who thinks that they know what the answer is, could make a lot more money than this production business, that's for sure.
So and think there's a lot of demand. There's airline destruction, cars, all that stuff. They say that's 30% demand destruction. I think that's going to take a while to get back to the 100%. I know there are other people with different views.
And if you actually knew also you could make some money. But all the stuff I get is from watching television. That everybody on television seems to know, but all they seem to know
a different number. Chris? Yes. Irene, on the differentials, generally, we've seen premium on our realizations compared to WTI. But like Steve said, we're trying to in the midst of all the volatility right now, you could have a couple of days that just throws it completely out of kilter.
But as this gets to be again more normalized over time, I would expect that premium to sort of be there. I just trying to quantify this is virtually possible.
Okay. Thank you.
Thanks.
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