Earnings Call Transcript - MGY Q1 2020

Operator, Operator

Good day, and welcome to the Magnolia Oil & Gas First Quarter 2020 Earnings Release and Conference Call. Today, all participants will be in a listen-only mode. 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.

Brian Corales, IR

Thank you, Chris, and good morning, everyone. Welcome to Magnolia Oil & Gas' First Quarter 2020 Earnings Conference Call. Participating on the call today are Steve Chazen, Magnolia's Chairman, President and Chief Executive Officer; and Chris Stavros, Executive Vice President and Chief Financial Officer. As a reminder, today’s conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on risk factors that could cause results to differ is available in the company’s annual report on Form 10-K filed with the SEC. A full Safe Harbor can be found on slide 2 of the conference call slide presentation with the supplemental data on our website. You can download Magnolia’s first quarter 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.

Steve Chazen, CEO

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 of the first quarter results, our current financial position and provide some broad guidance before we take your questions. Magnolia's strategy and business model have not changed. The quality of our assets and the characteristics of our business model have 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 on 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 first quarter. 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 first quarter. The current weak product prices do not justify bringing new wells online. As a result of our capital spending, we 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 fourth quarter or until we have some better clarity around product prices. Our spending for drilling and completions is expected to be less in aggregate for the remainder of the year than we spent in the first quarter. 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 million improvement in our 2020 cash operating costs and G&A compared with our original plan. Portions of these savings should be realized in the second quarter 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 have run a focused business. As a result, 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 to generate free cash flow 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 in natural gas wells. While we have not focused on this acreage during the last two years, we would consider allocating some capital as acreage should gas prices improve later this year. We expect that these wells to be fully competitive with Haynesville wells. In Giddings, we brought four new wells online during the first quarter 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 have 90-day average rates of 1,000 barrels of oil a day. The cost of these wells was 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 increase our confidence in future development opportunities in the field, with a 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-sized bolt-on oil and gas property acquisition 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 of process 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 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 opportunities that are most beneficial to our shareholders. I'd like to now turn the call over to Chris Stavros.

Chris Stavros, CFO

Thank you, Steve and good morning everyone. As Steve mentioned, I plan to review some high-level points from the first quarter, speak to some details around our cost-saving initiatives, and provide some guidance for the second 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 million of cash flow from operations. 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 first quarter. We've generated free cash in every quarter since the inception of the company. We repurchased one million Magnolia shares for approximately $7 million and closed on a bolt-on acquisition of primarily non-operating oil and gas properties in the Karnes area, for approximately $70 million. The acquisition closed in the second half of the first quarter and contributed less than 800 BOE per day of production to the quarter. We ended the first quarter 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 6, our total cash operating costs in the first quarter, 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 first quarter. Adjusted EBITDAX was $124 million in the first quarter with total drilling and completion costs of approximately $101 million or 81% of EBITDAX and lower than our guidance. Looking at slide 7 of the presentation, total production from the company averaged 68.4 thousand BOE per day during the first quarter a 10% increase compared to last year's first quarter and approximately the same as volumes in the fourth quarter of 2019. Oil production represented about 55% of our total volumes during the first quarter. 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 and we do not expect to issue any new debt. We have approximately $600 million of liquidity, including an undrawn $450 million credit facility. Our condensed balance sheet and liquidity as of March 31 are shown on slides 8 and 9. 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. Improvements in costs are largely comprised of savings from field-level operating expenses, gathering and transportation, general and administrative expenses, and contractor fees. The 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. We expect to see more overtime, 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 second quarter, 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 cost to decline about 10%, compared to 2019. In Giddings drilling and completion costs, on a multi-well pad, we 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 one 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 first quarter. 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 second quarter production to be in the range of 62,000 BOE per day to 65,000 BOE per day. We estimate our oil production to be approximately 52% to 54% of our total volumes. Looking at our second quarter expenses, unit cash operating costs including G&A are expected to decline about 5% from first 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 $1.9 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 approximately to $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 allow us to take advantage of potential attractive opportunities to further strengthen the company. We're now ready to take your questions.

Operator, Operator

We will now begin the question-and-answer session. Today's first question comes from Leo Mariani with KeyBanc. Please proceed.

Leo Mariani, Analyst

Yeah, I 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 just if prices stay low maybe that rolls off. So 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 it is a possibility in the fourth quarter. So what would you kind of see for that to happen?

Steve Chazen, CEO

We are currently under contract for the rig, but we have arranged for an extension with the contractor for next year or whenever we decide to proceed. Drilling costs are quite low, and although completion costs are different, drilling remains affordable. We are moving forward with drilling a three-well pad, which we expect to bring online possibly in the fourth quarter or more likely next year. I can't specify the price point at which we would resume, but the margins for these wells are broad once operational, allowing flexibility as long as completion costs are reasonable. I estimate we would begin completing wells in the low 30s, whether that's 30, 35, or another figure in that range, but only when we have more confidence in the economic outlook. Based on our operating costs and the $9 DD&A rate, we expect to start reporting earnings when we reach that price range. As an investor, that's what I'm focusing on.

Leo Mariani, Analyst

Okay. That's very helpful for sure. And I guess, just in terms of the recent drilling at Giddings, it 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? And do you think that several hundred locations is a pretty high probability at this point in time? What can you kind of tell us about the progress there?

Steve Chazen, CEO

The sample size is over 20 wells, and we've explored various areas. In one area, we have a strong level of confidence. Other areas have shown some promising results, but we haven't drilled many wells there. I believe the pad drilling will be effective in this promising area. I'm not certain how many locations there are, and given our current drilling pace, the number of locations will likely exceed my tenure. Therefore, I'm not worried about keeping track of locations. We have a very profitable business, and these wells do not decline; they produce a significant amount of oil and other products throughout their lifespan. If we manage to reduce costs to around $6 million per well, that would be significantly less than a Karnes well, with production potentially more than double, perhaps even triple, and with a lower decline rate. We will continue our work in Karnes, but I see this as a way to balance our business. In terms of product prices, it's wise to focus on these longer-life wells because while the prices may not be ideal today, if you maintain confidence over two to three years, the Giddings wells will offer better returns than the Karnes wells. In the Karnes area, product prices are high, which makes it appealing to drill extensively there due to the quick paybacks. However, Giddings represents a longer-term play where there is less certainty about oil prices. That’s my perspective on the matter today.

Leo Mariani, Analyst

I think that makes a lot of sense. And 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 first quarter. 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&A side and just kind of how you prioritize free cash flow from here on out?

Steve Chazen, CEO

Well, everything's got to compete with Giddings or Karnes. If the money is better spent completing Giddings or Karnes well, that's where the money will go. There's really nothing much to buy in Giddings, so there's really nothing there that will upgrade interest. And we have so much. There might be a few hundred acres here and there, but fundamentally nothing very large there. Most of the stuff isn't really in a different part of the basin that might be available, not all that interesting. Maybe we pay one or two times cash flow at $30 oil, some absorbent in price like that. So, if you go to Karnes, there's always a small piece around. 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 foresee for the next couple of years, drilling locations are going to be rare and special. I think there are a lot of locations around. I'm not really concerned about locations, right now. I'm concerned about cash flow generating.

Leo Mariani, Analyst

Okay great. Thank you.

Steve Chazen, CEO

Thanks.

Operator, Operator

The next question comes from Jeff Grampp with Northland. Please proceed.

Jeff Grampp, Analyst

Good morning everyone. Steve, I found your comment about the potential for gas in Giddings to be intriguing, and I’d like to explore that further. Can you provide an overview? I assume the gas prices need to be competitive with the oil opportunities you have, which introduces some variability. On a rough estimate, is there a gas price that makes sense in relation to oil? Perhaps you can reference 2021 strip prices as a benchmark. I’m trying to understand what that point might be where it becomes more appealing.

Steve Chazen, CEO

The wells have been performing well. However, we likely won't take action until gas prices approach $3. They also produce some liquids, not just dry gas, with around 20% liquids content. NGL prices are currently very low, and they produce some oil as well, which factors into the equation. I believe we're closer to $3 than $2. We could drill at the Giddings oil well even at $30, which is more appealing than drilling gas wells. However, we could also drill many high-volume gas wells if we wanted to increase our BOEs, and that would be the way to do it.

Jeff Grampp, Analyst

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 efficiency that you're seeing from doing pad development, that's driving that versus maybe just generic kind of oilfield service company type of cost...

Steve Chazen, CEO

It's not driven by oilfield service guys. You get little better crews now than you had before because we weeded out some of their crews. But it's driven by the fact that 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 and guessing what you're doing and trying to learn. 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.

Jeff Grampp, Analyst

Got it. Sounds good. I appreciate the time.

Steve Chazen, CEO

Thanks.

Operator, Operator

The next question comes from Will Thompson with Barclays. Please proceed.

Will Thompson, Analyst

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 marketing arrangements look like and whether you expect any impact from the CMA role? You mentioned reducing GP&T costs in that $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?

Steve Chazen, CEO

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 whatever. We basically sell locally. Some of the Giddings wells are trucked but that's in the cost. Ultimately, we'll deal with that. There's a pipeline that we could acquire – it was one there that we could refurbish once we get going again. I'm not – 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 for speculation on oil price. Again, I figure I've got a lot of locations; I don't need to do that. I don't really have a way of predicting oil prices. I can 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. And somebody – other people have different objectives. They may have different cost structures. They may have take-or-pay requirements up in 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 doesn't – it's not like putting oil in the tank and then just moving the tank. That recovery is spread over several years. So I'd 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 than June will be better. So I'm not really – I set up the same business model that somebody else might have that might be five or six basins and it's got a lot of overhead and has made 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 – wells generate 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 if – it's like running a private business as opposed to trying to optimize something for a 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.

Will Thompson, Analyst

Okay. That's helpful color. And then in terms of Giddings, where are you in terms of completion designs, proppant intensity, etc.? Just trying to understand are you still tinkering with well design? And I know your only challenge in Giddings is that well cost. Giddings well cost's down was that you were 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?

Steve Chazen, CEO

It's well pad; a small pad would be about $6 million. Listen, I don't view that as the ultimate objective. That is just what's obviously visible now. Once you get there, you move the goalpost. You have to decide that you're going to – this business is not at $80, $70, $60, or $50 a barrel oil business or 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 better. It may be a little better. But I don't think you should 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 of how you spend your money. You need to spend money on stuff that works in the 30s.

Will Thompson, Analyst

Looks 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 sense on...

Steve Chazen, CEO

There really isn't much change. We've monkeyed with this a lot. I'm sure it'll be tweaked. But right now, we'll get it down to the $6 million 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, if you can produce 1000 barrels of oil a day wells for 90 days or longer and with a much lower decline than Karnes, the completion design is probably okay for now.

Will Thompson, Analyst

Okay. Thank you.

Steve Chazen, CEO

Thanks.

Operator, Operator

Our next question comes from Neal Dingmann with SunTrust. Please proceed.

Neal Dingmann, Analyst

Good morning all. Steve, just maybe add on to what you were just saying on the Giddings if you could just add a couple more details. I know not long ago, you'd mentioned, I think you now 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 your estimates or forecast forward, are you anticipating that part of that $6 million cost that cost continues to fall? Or maybe just talk about what you're anticipating on the...

Steve Chazen, CEO

I don't feel sorry for service companies and won't be confused in this discussion. However, I think they could reduce costs and pay their CEOs less, as I’ve done in other places. Nevertheless, we’re not counting on that. I believe they are close to maximizing efficiency. The value in a service company comes more from the quality of the crews rather than their hourly or daily charges. If they recruit crews from Huntsville, they'll see similar outcomes. Experienced crews lead to better results, and it’s primarily about their quality rather than the exact rates they charge. We pay a bit more for better crews since all they need is 1.5 days per barrel. Generally, as the business grows, crew quality can decline, leading to poorer results and higher costs. Service companies may not be getting rich due to competition, but their desire to improve is there. The key factor is maintaining high-quality crews, but we’re not counting on significant cost reductions as I don’t think there’s much more room for that.

Neal Dingmann, Analyst

Okay, that's a valid point. You mentioned this earlier, but I’m curious about your approach during downturns like this regarding shut-ins, drilling and completion suspensions, and docks. When considering all of that, Steve, you often mention that drilling doesn’t make sense at these price levels. However, I’d like to know if there's anything more to your perspective on this. You've implemented some shut-ins and are planning significant drilling and completion suspensions. Could you share your thoughts based on your past experiences?

Steve Chazen, CEO

We have only shut in what doesn’t make sense. We are not managing production like others might be. A quarter of our production is operated by others, and if they don’t communicate with us, we rely on run rates or press releases to understand the situation. The motivations behind their actions are unclear; larger companies might be managing prices or adhering to contracts without us knowing the full story. Regarding drilling, we secured a contract with a contractor and obtained favorable prices for drilling some wells, which aligns with our plans. For completions, we will wait for more clarity on product prices. I expect that at some point, third-party operators will resume activity in Karnes as cash allows. While I'm not keen on building docks, we will proceed with some projects, as I am confident that oil prices will reach the 30s. If I believed we needed prices to reach the 50s, I wouldn’t invest in docks.

Neal Dingmann, Analyst

Thanks. I really appreciate the time. Thanks.

Steve Chazen, CEO

Sure.

Operator, Operator

The next question comes from Jeffrey Campbell with Tuohy Brothers. Please proceed.

Jeffrey Campbell, Analyst

Good morning. Thanks for taking my question. Steve regarding the extra Giddings locations that were identified in the pre-analogs, I was wondering does this center mainly on the recent success area? Or was this kind of a broader number referring to all appraisals done?

Steve Chazen, CEO

No, it's centered on where we're doing the development drilling.

Jeffrey Campbell, Analyst

Okay, great. Thank you. And most every E&P says it's aligning its corporate structure to the current reality, but 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? And how far out into the future are you looking to make these judgments?

Steve Chazen, CEO

Yes, the G&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.

Jeffrey Campbell, Analyst

Okay. Thanks.

Steve Chazen, CEO

You might remember that we have a contract with Enervest for some of the back office and some of the well management, that sort of thing. And so that might be a target for reduction.

Jeffrey Campbell, Analyst

Thanks. And that actually 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?

Steve Chazen, CEO

No, we'll use our own. We could do that now.

Jeffrey Campbell, Analyst

Okay. Thank you.

Operator, Operator

The next question comes from Biju Perincheril with Susquehanna. Please proceed.

Biju Perincheril, Analyst

Good morning, all. Thank you for taking my question. Thinking about when you're all 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?

Steve Chazen, CEO

The first rig and the first completion crew will go to Giddings. We will likely place a completion crew in Karnes around the same time since we have some facilities there. In terms of drilling, I expect that the next drilling will occur in Giddings. If oil prices are around $35, then it would likely be in Giddings. If prices are $45, we would most likely move our rig to Karnes. It really depends on how certain I feel over time about the direction of prices. If there's a high level of uncertainty and volatility, you might invest more in Giddings and less in Karnes. Conversely, if prices spike, we could drill many current wells because the returns are quick. Producing wells at 4,000 barrels a day can pay back quickly, after which there’s a consistent low-cost production stream. It’s a lucrative scenario where you can quickly recover your investment and benefit from long-term production.

Biju Perincheril, Analyst

That's very helpful. And my follow-up was on the gas optionality you talked about. Those wells, are those much deeper there an appreciable difference in well cost that you expect for the gas...

Steve Chazen, CEO

They're somewhat more expensive. But, 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. If they're somewhat more expensive, I want to guess it's a $7 million well or an $8 million well, but not a $10 million well. But that's just a guess.

Biju Perincheril, Analyst

That's helpful. Thank you.

Operator, Operator

Our next question comes from Kashy Harrison with Simmons Energy. Please proceed.

Kashy Harrison, Analyst

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.

Chris Stavros, CFO

We just don't know right now. We can see the current period, but beyond that, what is encouraging is the performance from Giddings and the decline rate. It's clearly a more efficient operation, which is why we're prioritizing investment there. Additionally, our other gas production has certainly contributed to improving the decline rate and overall production efficiency, but I can't provide details on an exit rate at this time.

Steve Chazen, CEO

We're just lucky we can do next month on an exit rate. So I figured being able to figure June was a major victory.

Kashy Harrison, Analyst

All right. Fair enough. And then Steve, maybe one for you. You mentioned earlier the need to adjust the business based on the current price. I was wondering how we should think about inventory depth if we expect these prices to remain around $35, $40, and $45 for a while. How many locations might we lose, or is the inventory situation you discussed in the past still mostly the same? And how does this relate to sizing the economic inventory?

Steve Chazen, CEO

Yes, we have managed the risks associated with Giddings. It performs adequately in a $35 environment, and potentially more locations could be viable in a $60 environment. Karnes is similar in that regard. We've generally not operated many high-cost wells that need $55 or $60, apart from a few marginal wells in Karnes that are outside the main area. Our inventory isn't significantly affected by changes in market prices, which is why we only see a slight reduction in our shut-in wells. When a workforce is focused on a specific area, it creates more flexibility compared to a setup spread over multiple basins where costs can escalate. We approach this business as if it's our own money at stake rather than a third party's.

Kashy Harrison, Analyst

That's understandable. I appreciate the clarification. I have a quick housekeeping question. You mentioned that the lateral length on the Giddings wells is about 20% to 25% longer than last year. I'm curious about the actual lateral length for these pads. Also, does this indicate your long-term perspective on the lateral length of the wells you aim to target in Giddings, or do you anticipate they might continue to get longer over time?

Steve Chazen, CEO

We are currently producing around 6,000, having previously been below 5,000. We don’t face constraints like lease limitations in many areas. However, we would likely choose to experiment during a higher price environment to see if it proves effective, rather than trying to push the model and take unnecessary risks at this time.

Kashy Harrison, Analyst

Got it. It makes sense. Okay. Thank you.

Steve Chazen, CEO

Thanks.

Operator, Operator

Our next question comes from Brian Downey with Citigroup. Please proceed.

Brian Downey, Analyst

Good morning. Thank you for the questions. Chris, Steve mentioned earlier that the industry requires less interest and less debt. Currently, there are no credit facility balances. As you consider capital allocation, Magnolia's senior notes have recently been trading between $0.80 and $0.85 on the dollar, based on what we’re seeing. Have you thought about using cash on hand or available credit to repurchase any of those notes below par? Would there be any limitations or challenges if you decided to pursue that strategy in the open market? And could this be included in the Magnolia capital allocation strategy?

Chris Stavros, CFO

Probably not right now. I mentioned some limitations. I'm not certain how liquid it is for stocking up, but it’s likely not enough to make a significant impact.

Steve Chazen, CEO

Yes. The other part of it is that we have five more years until maturity.

Chris Stavros, CFO

Yes. Six actually.

Steve Chazen, CEO

You still have quite a bit of time ahead. It's not worth giving up that optionality for a minimal gain. Our interest expense is six times $424 million a year. If you decided to purchase it for $0.80, now you would only save around $20 million, which is hardly anything. It doesn't justify sacrificing the peace of mind of not having to repay it for a while. Many people have significant discounts, some reaching 60% or 70% on large amounts, which can start to make sense. However, in our case, buying $1 million at $0.85 would be difficult. I appreciate having the optionality with the debt we currently have.

Brian Downey, Analyst

Got it. That's helpful. Thanks for taking my question.

Steve Chazen, CEO

Sure.

Operator, Operator

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