Good day, and welcome to the Magnolia Oil & Gas Q1 2020 earnings release and conference call. Today, all participants will be in a listen-only mode. Should you need assistance during today's conference, please signal for a conference specialist by pressing the star key followed by zero.
After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touch-tone phone. To withdraw your question, please press star then two. Please note that today's event is being recorded. At this time, I would like to turn the call over to Brian Corales. Please proceed.
Thank you, Christopher. Good morning, everyone. Welcome to Magnolia Oil & Gas' Q1 2020 earnings conference call. Participating on the call today are Steve Chazen, Magnolia's Chairman, President, and Chief Executive Officer, and Christopher 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 Q1 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, 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.
Christopher will review some of the details of the Q1 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 million of cash in our balance sheet, $450 million of undrawn revolver, and $400 million 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 million 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 is expected 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 completions is expected to be less in 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 a $55 million improvement in our 2020 cash operating costs in G&A compared with our original plan. A portion of these savings should be realized in the Q2 and more fully captured in the second half of the year.
Our cost reduction initiatives will remain an ongoing effort throughout the remainder of the year. As a company, we run a focused business. A 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 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 Q1 , 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 is capable of producing high flow rate natural gas wells.
While we have not focused on this acreage during the last two years, we would consider allocating some capital to this acreage should gas prices improve later this year. We expect that these wells will be fully competitive with Haynesville wells.
In Giddings, we brought four new wells online during the Q1 with an average 60-day oil production rate of 800 barrels a day per well. Two 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 increases our confidence on the future development opportunity in the field with the potential for several hundred drilling locations.
Giddings would be the first area where we would bring back a rig and complete wells as product prices recover. We continue to evaluate several small to mid-size bolt-on and oil and gas property acquisitions opportunities.
While the M&A market has been stagnant so far this year due to the weakness and volatility in product prices, there are some signs the process is beginning to loosen. We expect opportunities to expand our business will appear later this year once the 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,
As well as our cash overhead and our interest payments, at least 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 opportunities that are most beneficial to our shareholders. I'd now like to turn the call over to Christopher Stavros.
Thank you, Steve. Good morning, everyone. 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 Q2 before turning it over for questions.
Looking at our quarterly cash flow summary on slide five of the conference call presentation posted on our website, we generated $135 million of cash flow from operations, and our total cash outlays associated with drilling and completing wells was $94 million during the quarter. Free cash flow after changes in working capital and capital spending was $23 million during the Q1 , and we've generated free cash in every quarter since the inception of the company.
We repurchased 1 million Magnolia shares for approximately $7 million and closed on a bolt-on acquisition of primarily non-op oil and gas properties in the Karnes area for approximately $70 million. The acquisition closed in the second half of the Q1 and contributed less than 800 BOE per day of production to the quarter.
We ended the Q1 with $146 million 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 six, our total cash operating costs in the Q1 , including G&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 million in the Q1 , with total drilling and completion costs of approximately $101 million, or 81% of EBITDAX, and lower than our guidance. Looking at slide seven 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 2019. Oil 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 million in senior notes remains unchanged in the quarter. We do not expect to issue any new debt. We have approximately $600 million in liquidity, including an undrawn $450 million credit facility.
Our condensed balance sheet and liquidity as of March 31st are shown on slides eight and nine. To summarize, Magnolia is financially well positioned to manage through the current challenging period of weak product prices. As part of our cost reduction initiatives in response to much weaker product prices, we expect to achieve approximately $55 million of savings in our 2020 cash costs 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. A 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 expected our average well costs 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 program 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 Giddings field 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 in 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 will 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 Q2 production to be in the range of 62,000-65,000 BOE per day.
We estimate our oil production to be approximately 52%-54% of our total volumes. Looking at our Q2 expenses, unit cash operating costs, including G&A, are expected to decline about 5% from Q1 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 $1.9 billion non-cash pre-tax asset impairment due to significant weakness in product prices.
As a result of the impairment, we estimate our DD&A rate should decline 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 in 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 session. To ask a question, you press star then one on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw it, please press star then two. At this time, we will pause momentarily to assemble our roster. Today's first question comes from Leo Mariani with KeyBanc Capital Markets. Please proceed.
Yeah. 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.
I was hoping you could address that. 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 need to see for that to happen?
I think we start with the rig. The rig's 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. I think it's so cheap to drill, and it isn't that much money. Completion's a different story, but it's so cheap to drill that we decided to go ahead and drill.
This is a three-well pad that we're drilling. 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. 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. 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'd start completing wells. Probably not before that, and probably not until we had more confidence in where the economy is headed.
Somewhere in that area. If you take our operating costs that Christopher talked about, and G&A and all that other stuff, and take the $9 DD&A rate, somewhere in that 30s, we'll start to report earnings. 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. I guess just in terms of the recent drilling at Giddings, certainly looks like that two-well pad was a rousing success. You guys mentioned potential for several hundred 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? Do you think that several hundred locations is a pretty high probability at this point in time? What can you tell us about the progress there?
Well, sample size is 20-some wells. We've 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. I think the pad drilling will work in this good area. I don't really know how many locations there are. Given the current pace of drilling, it's.
The locations will significantly outlast me. I'm not really concerned about counting up locations. 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 million a well, that's 50% more, say, than a Karnes well, with more than twice as much production, maybe 3x the production, with a lower decline.
We'll continue working on Karnes, of course, but I think this will provide a ballast to the business. 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 two or three years, you'll do a lot better in the Giddings wells than you will in a Karnes well.
Karnes well, as we look at it, product prices are high. You drill a hell of a lot of Karnes, because you got real short paybacks. In the Giddings is for the 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. Just lastly, on M&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 a legacy deal negotiated.
Right.
Towards the end of the year that sort of closed here. Maybe just talk more about what you're seeing on the M&A side and just how you prioritize free cash flow from here on out?
Everything's got to compete with Giddings or Karnes. If the money is better spent completing Giddings or Karnes wells, that's where the money will go. There's really nothing much to buy in Giddings, so there's really nothing there that's of great interest. We have so much, there might be a few hundred acres here and there, but fundamentally, nothing very large there.
Most of the stuff is in really in a different part of the basin that might be available, and not all that interesting. Maybe we'd pay one or 2x cash flow at $30 oil or some exorbitant price like that. If you go to Karnes, there's always small pieces around. As some of these private equity things unwind, we might find some there. We're not going to be big payers there because right now, we got a pretty long runway.
I don't view that in this environment or the environment I foresee 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 generation.
Okay, great. Thank you.
Thanks.
The next question comes from Jeff Grampp with Northland. Please proceed.
Morning, guys. Steve, I thought your comment on maybe gas making some sense in Giddings to get after was interesting. 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 opportunities you have.
There's a little bit more variability in that. Ballpark, is there a gas price maybe relative to oil? I don't know if you look at maybe 2021 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 till we got closer to $3 for gas, because they also produce some liquids. They aren't dry gas wells. They got about 20% liquids. NGL prices, which are in the toilet right now, and it produces some oil, It's got some of that to it.
I think it's probably closer to $3 than $2. We could drill a Giddings oil well, even at $30, easier and more attractively than gas wells, but we could drill a lot of gas wells, high volume gas wells. If we wanted to inflate our BOEs, that would be the way.
All right. Understood. On the cost cuts at Giddings, the 20% number that you guys referenced, can you 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 oil field service company type of cost cutting?
It's not driven by oil field service guys. You get a little better crews now than you had before because they've weeded out some of their crews. 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 an experimental phase, if you want to think of it that way. It's principally driven by knowing what you're doing as opposed to trying to guess what you're doing and trying to learn. I think we'll be down another 10%. Once we start completing the wells. 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.
Good morning, everyone. Steve, what would cause you to be more proactive about shutting production? Maybe can you remind us what your marketing arrangements look like, and whether you expect any impact from the CMA roll?
You mentioned reducing GP&T costs, and that's $55 of cash savings. Correct me if I'm wrong, but I believe a lot of the Giddings barrels were 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 or Oxy or somebody might be able to influence the product price. A lot of them have long transportation. They've got to transport from the Permian to wherever. We basically sell locally.
Some of the Giddings wells are trucked, but that's in the cost, and ultimately, we'll deal with that. There's an oil pipeline that we could acquire. There's one there that we could refurbish, if you want to think of it that way, once we get going again. There's more money there to be had down the road. Not right now, but down the road. Trucking is easier. If the well contributes to free cash in a predictable way, we're going to produce.
We're not going to shut in to speculate on oil price. Again, I figure I got a lot of locations, I don't need to do that. I don't really have a way of predicting oil prices. I could prove that to you if I had to. I think you've got to run this like a real business, not some wacky oil business. 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, it's not like putting oil in a tank and then just moving the tank.
That recovery is spread over several years. I'd just as 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. We'll survive May, and June looks a little better, and June will be better. I'm not really It's just not the same business model that somebody else might have that might be in five or six 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. This is sort of a simple business. If a well generates free cash, we'll run the well. If not, we won't. We look at that every day on each well. It's a pretty straightforward calculation.
It would be just like running a private business as opposed to trying to optimize something for a public business. I'm not really worried about. We can make lots more production next year if we need it. Obviously, even if we didn't produce anything, we're probably not going to move the product price.
Okay. Helpful color. In terms of Giddings, where are you in terms of completion designs, proppant intensity, et cetera? Just trying to understand, are you still tinkering with well design?
Not really.
I know one challenge in getting is that well costs, getting well cost down was that you weren't moving to larger pad development, just given that you're still in delineation mode. You mentioned $6 million is the opportunity. Does that include moving to larger pad development?
It's what a small pad would be, about $6 million. I don't view that as the ultimate objective. That's just what's obviously visible now.
Okay.
Once you get there, you move the goalposts. You've got to decide 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. It may be a little better, but you can no longer run your business as if oil's going to be $65 forever. 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.
It seems like some of your peers are learning the hard way. Just on the follow-up, just in terms of the completion design, can you just give us a frame?
There really isn't much change.
Okay.
We've monkeyed with this a lot. I'm sure it'll be tweaked. Right now, we'll get it down to the $6 million run rate, and then we'll look at it again, see if something we can do to take another 10% out. Right now, if you can produce 1,000 barrel of oil a day wells for 90 days or longer, with a much lower decline than Karnes, completion design's probably okay for now.
Okay. Thank you.
Thanks.
Our next question comes from Neal Dingmann with SunTrust. Please proceed.
Morning. 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.
I'm just wondering for you or Christopher and maybe in some of your estimates or forecasts forward, are you anticipating that part of that $6 million cost, that cost continue to fall or maybe just talk about what you're anticipating.
No. We're not. I never feel sorry for service companies, so I don't want you to be confused in this discussion, but I always think they could cut more and could work for less. Tell them they cut their CEO pay down to mine. Half that. Anyway. I already tried that. I already did that experiment some other place.
Anyway, we're not counting on that. I think they're pretty close. Where you gain, to be honest, in a service company is not what they charge per hour or per day or whatever. It's the quality of the crews. If they recruit their crews at Huntsville, then you're gonna get Huntsville-style outcomes. If these are experienced people who've been around, and these are the people they're trying to protect, you're gonna really get good outcomes.
It's much more about the quality of the crews than about exactly what they charge you. 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. 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 soar.
It isn't that the service companies get rich, because there's too much competition, but not that they don't want to get rich. I really think that's the key element. We are counting on that the crews stay good quality crews. 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 a fair point. Then you touched on this, but I'm just 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,
Steve, 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've shut in a little bit. You're going to have much more major D&C suspensions. I'm just wondering, could you just talk about giving 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. About a quarter of our production's outside-operated.
They don't actually communicate with us. The reason we know what's going on is we see the run rate. We read their press releases. You don't really know what the motivation is. Again, a large company may think it's managing price. It 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. We'll drill those wells. As far as completions go, we'll wait until we got more clarity on product prices.
I'm guessing that's somewhere in the 30s. Then in Karnes, I assume that the third-party operators, the outside operators will pick up at some point there, I guess. I don't like building DUCs, but we are going to build some. 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 DUCs.
Thanks. Really appreciate the time. Thanks.
Sure.
The next question comes from Jeffrey Campbell with Tuohy Brothers. Please proceed.
Good morning. Thanks for taking my question.
Great.
Steve, regarding the extra Giddings locations that were identified in the pre-analysis, I was wondering, does this center mainly on the recent success area, or was this kind of a broader number referring to?
No.
Appraisal done?
No, it's centered on where we Not so recent, but where we're doing the development drilling going.
Okay, great. Thank you. Most every E&P says it's aligning its corporate structure to the current reality. Magnolia seems to have used more of a scalpel than a machete compared to some peers. Is G&A largely where you want it currently? How far out into the future are you looking to make these judgments?
Yeah. G&A is not where we want it to be. It needs to be reduced sharply. We're working on a plan to reduce it materially from here.
Okay, thanks. My last,
You might remember that we have a contract with EnerVest for some of the back office and some of the well management and that sort of thing. That might be a target for reduction.
Okay, thanks. 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 the current operating arrangement?
No. We'll use our own. We could do that now.
Okay, thank you.
But we,
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. First rig and the first completion crew will go to Giddings. We'll probably put a completion crew in Karnes at similar time because we have some DUCs there. As far as drilling, I would think the next drilling would be in Giddings. I just don't know. If oil's $35, it'd probably be Giddings.
If oil's $45, we'd probably put a rig into Karnes. 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 volatile meaning bad volatile, not up volatile, then you probably would spend more in Giddings and less in Karnes. If you had a spike in prices, we might drill a lot of Karnes wells. Because the payout's real quick.
You produce 4,000 barrels a day wells or something like that, and you get your money back real quick. Then you've got a long, low cost stream after that. It's a good well, but it's a good well where you can reap a lot of money up front, get your money back real quick.
That's very helpful. My follow-up was on the gas optionality you talked about. Those wells, are those much deeper? Is there an appreciable difference in well cost that you'd expect for the gas well versus?
They're somewhat more expensive. Of course, we haven't drilled one, and we're not using some of the stuff we've learned since, so I don't really know what it would run us. They're somewhat more expensive. I'm going to guess it's a $7 million well or $8 million well, not a $10 million well. 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, thanks for taking my questions. Christopher, 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 of that or activity you would need to hold that production flat at least through 2021.
We just don't know right now. We sort of see out into the current period, but beyond that. What is encouraging is what you're seeing out of Giddings and the decline rate. It's a more efficient operation, which I think is what's leading us to allocate money there first.
That and the other gas production that we have has certainly helped the decline rate and the efficiency of the production overall. I can't speak to an exit rate right now.
We're lucky we can do next month on an exit rate. I figured being able to figure June was a major victory.
All right. Fair enough. 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. So I was just wondering how we should think about Or maybe it doesn't involve,
but how you think about inventory depth if we are, 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've talked about in the past still pretty much unchanged?
The Giddings stuff.
I mean economic inventory.
Yeah. The Giddings stuff, we've taken care of the risking of that. That sort of works in this $35 sort of environment. It might be more locations in a $60 environment. Karnes, I think it works in the same general area. We never had a lot of high wells that required $55 or $60. It was 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, reasonable product price changes. That's why we only have a small reduction in our shut-in wells because the wells sort of work. If you have a workforce that's focused in just a narrow area, you get a lot of flexibility.
If somebody in five basins just doesn't have that kind of flexibility and his business is inherently more costly, just run sort of like you would run if it was your money rather than some third party's money.
Makes sense. That's helpful. Then maybe just a minor housekeeping question from me. 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 lengths 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 five sort of before. A lot of times, some places you're limited by your leases. We don't have that kind of constraint. 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. Christopher, 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-$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? 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. To talk about limitations, I'm not sure 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, we've got five more years on maturity.
Yeah. Six, actually.
You got a while to go here. To give up that optionality for a very small gain Because I just view it, our interest expense, 6x 400 is $24 million a year. If you could buy it all for $0.80 on the dollar, so now you're down to $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.
A lot of people have pretty wide discounts. Some guys are 60% discount, 70% discount in large sums. It sort of starts to make sense. It just doesn't make a lot of sense. When we look at it, buying $1 million at $0.85 would be challenging. I sort of like the optionality of the debt out there so far.
All right. That's helpful. Thanks for taking it. Thanks.
Sure.
As a reminder, if you do have a question, please press star then one. 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 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, Christopher can talk about product price. 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 -$55, just screws up the whole calculation because it's the average over the month.
Anybody who thinks that they know what the answer is could make a lot more money than this production business, that's for sure. I think there's a lot of demand. There's airline destruction, cars, all that stuff. They say that it'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.
If you actually knew, also you could make some money. All the stuff I get is from watching television, and everybody on television seems to know, but they seem to know a different number. Christopher?
Yeah, Irene, on the differentials, generally we've seen a premium on our realizations compared to WTI. Like Steve said, in the midst of all the volatility right now, you could have a couple of days that just throws it completely out of kilter. As this gets to be, again, more normalized over time, I would expect that premium to sort of be there. Just trying to quantify it is virtually impossible.
Okay. Thank you.
Thanks.
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