Devon Energy Corp (DVN) — Q1 2020 Earnings Call Transcript

Good morning and thank you to everyone for joining us on the call today. Last night, we issued an earnings release and presentation that covers our results for the quarter and updated outlook for the year. Throughout the call today, we will make references to our first quarter earnings presentation to support our prepared remarks, and these slides can be found on our website at devonenergy.com. Also joining me on the call today are Dave Hager, our President and CEO; David Harris, our Executive Vice President of Exploration and Production; Jeff Ritenour, our Chief Financial Officer; and a few other members of our senior management team. Comments on the call today will include plans, forecasts and estimates that are forward-looking statements under US Securities law. These comments are subject to assumptions, risks and uncertainties that could cause our actual results to differ from our forward-looking statements. Please take note of the cautionary language and the risk factors provided in our SEC filings and earnings materials. With that, I’ll turn the call over to Dave.

Thank you, Scott, and good morning. It is my sincerest hope that everyone listening today is staying safe and in good health. As you all know, since our last earnings call, it's been an extraordinary time in the energy markets with an unprecedented demand shock related to COVID-19 resulting in a rapid and historic decline in oil pricing. While no one could have accurately predicted the timing or wide range of impacts of this pandemic on the global economy or our industry, I am confident that Devon has entered this period of volatility with an extremely firm foundation. Our combination of strong liquidity, low financial leverage, high-graded portfolio, and top-tier operating capabilities leave us well-positioned to navigate these challenging times effectively. Adding to these competitive advantages is our talented team here at Devon. I want to take a moment to recognize all of our employees for their hard work and dedication during this period of dislocation due to COVID-19. Their focus on safely executing our business plan and protecting shareholder value has led to another quarter of outstanding operational results. The results for the first quarter were highlighted by capital expenditures coming in 12% below midpoint expectations, higher oil production than our previous guidance, and our cost savings initiatives continue to trend ahead of plan, and we generated free cash flow in the quarter. All-in-all, we are executing at a very high level, and I want to thank our employees for their commitment to excellence. The rest of my prepared remarks today will cover a handful of key messages that provide insight into our approach to managing the business through these turbulent times. Then I'll turn the call over to Q&A where we'll answer as many of your questions as possible. The first key message I want to convey today is that we have the financial strength to withstand an extended downturn. As you can see on slide three of our earnings presentation, Devon had $4.7 billion of liquidity, consisting of $1.7 billion of cash and $3 billion of undrawn capacity on our credit facility at the end of the quarter. In addition to our substantial cash balances, Devon's liquidity is further enhanced by our senior unsecured credit facility, which matures at the end of 2024. This facility contains only one material financial covenant, a debt-to-capitalization ratio below 65%. At quarter end, this ratio was less than 20%. The facility is fully committed to us, and we are not subject to semi-annual redeterminations. Lastly, a key event additive to our liquidity over the remainder of 2020 is our recently amended agreement to sell the Barnett Shale. Under the revised terms, we agreed to sell our Barnett Shale assets for up to $830 million, consisting of $570 million in cash at closing and contingent payments of up to $260 million. This agreement includes a $170 million deposit, which we received in April, and we are on track to close the transaction by year-end. Also adding to Devon's financial margin of safety is our low average with no outstanding debt obligations until the end of 2025. On the right-hand side of slide three, you can see that our near-term debt maturity runway is best-in-class within our peer group, with nearly 6 years of time until our first tranche of debt comes due. This is a critical competitive advantage in this period of extreme commodity price volatility. The second key message I want everyone to understand is that Devon is committed to living within cash flow. Our top priority in this environment is to protect our financial strength. To do that, we have taken decisive actions to protect our revenue and align our business with industry conditions by aggressively reducing capital and operating costs. Looking specifically at revenue, Devon's disciplined hedging program has protected approximately 90% of our expected oil production for the remainder of 2020 at an average WTI floor price of $42 per barrel. We have also taken steps to protect about half of our expected oil volumes for the first half of 2021 at prices that are nearly $40 per barrel. Additionally, to protect against the risk of widening in-basin differentials, we've utilized regional basis swaps to lock in pricing for the vast majority of our Eagle Ford and Delaware Basin oil volumes for the remainder of the year. In aggregate, the estimated market value of our go-forward derivative position is roughly $750 million, a substantial contributor to our cash flow in 2020. On the cost front, the most significant changes we have made to date are related to the reduction of our capital activity levels. With our revised capital plan, we have limited our spending outlook to $1 billion in 2020, a decline of 45% compared to our original budget. As outlined on slide seven, we have elected to continue to invest and preserve operational continuity in the Delaware Basin to generate the necessary cash flow to operate our business while suspending all capital activity in the Anadarko, Eagle Ford, and Powder River plays until market conditions improve. While we believe this is a prudent program for the current environment, given the uncertainty regarding the depth and duration of this pricing downturn, I do want to highlight that we have tremendous flexibility with our go-forward capital plans. We have minimal long-term contract commitments. Our opportunity set consists of only short-cycle onshore projects, and we have no significant lease expiration issues. With these characteristics, we are fully capable and willing to swiftly adjust activity levels as market conditions evolve. In addition to the capital reductions, we are also improving our cash flow by targeting approximately $250 million in cash cost reduction by year-end. This cost reduction plan includes a range of actions to lower field-level operating expenses and continue to optimize the organization’s overhead. This includes an expected 40% reduction in cash compensation for our executive management team year-over-year. While we have a clear line of sight on this $250 million of cost savings, we are not done. There are several initiatives underway that will further trim our cost structure, and I expect to provide updates on these initiatives in future calls. To summarize on slide 12, you can see the cash flow impact as swift and decisive changes we have made year-to-date. Our hedging program and intense focus on costs have positioned us to fully fund our capital requirements and dividend while generating net cash inflows at a price deck of $20 WTI for the remainder of the year. The next topic I want to touch on is our plan to dynamically manage production as storage levels become constrained and regional pricing weakens. With today's challenged commodity price backdrop, we are being mindful not to accelerate valuable production into these weak markets. To combat these conditions, our first course of action is to reduce our current completion activity levels by approximately 65% from the first quarter. This decision to limit the wells we bring online will position us with a DUC backlog of nearly 100 wells company-wide at year-end. For those wells that we have brought online recently, we restricted the full raise to ensure that we do not deliver flush production into these tough markets. Next, with regard to our base production profile, the operating teams have performed a detailed analysis to identify uneconomic wells at various price levels across our portfolio. The decision to shut in or curtail production from existing wells is generally made when the variable cost to operate the well exceeds its expected revenue. While that is the primary decision point, other factors may influence this decision as well, such as leasehold considerations, mechanical risks, and involuntary third-party constraints. We plan to proceed with curtailment decisions on a month-to-month basis. But for the second quarter, we expect to defer roughly 10,000 barrels per day of oil across our portfolio. Of this amount, only 20% is driven by the shut-in of production. The vast majority of curtailments are related to the restricted flow back of higher-rate wells and the deferral of bringing a few new wells online in the second quarter. The minimal shut-in activity reflects the quality of our assets and the good work our team has done to place volumes. First, we have no pricing exposure to West Texas light, Clearbrook, the North Slope, Canadian Bitumen, or many other well-known pricing hubs that have recently experienced exceptionally weak prices. Furthermore, in key plays like the Eagle Ford and Powder River Basin, we correctly anticipated that there would be weak regional pricing, and our marketing team took early and decisive action to lock in our revenue at pricing above variable costs in May and June. Taking all these factors together, our production operations are well positioned to be resilient in the face of these challenging conditions. Looking ahead, the next key message I want to emphasize is our ability to capitalize on the recovery when industry conditions normalize. The decision to exit our heavy oil position in Canada, sell the Barnett shale, and monetize our controlling stake in Enlink Midstream have helped set the foundation for the advantageous position we operate from today. These bold moves have dramatically improved our financial strength, asset quality, and competitive position on the marginal cost curve. Devon's go-forward portfolio now consists of only large contiguous stacked pay acreage positions and the best parts of the best plays in the US. Importantly, within this portfolio, Devon has established a track record of operational excellence that is supported by consistent capital efficiency gains. A great example of this efficiency is on slide 17, which highlights our Wolfcamp program, where the majority of our capital is invested in 2020. Our drilled and completion costs in the first quarter improved by 42% to $705 per foot. To better appreciate this success, I encourage everyone to compare this top-tier result to our peers in the Delaware Basin. These Wolfcamp improvements are underpinned by steadily improving cycle times and optimized completion designs. We expect these efficiencies to continue throughout the remainder of 2020 and into 2021. These efficiency gains have allowed us to preserve operational continuity even as we limit capital investment. As you can see on slide 18, assuming no curtailment beyond the middle part of the year, we expect our oil production profile to be nearly flat compared to the average of 2019, and we are in a good position to stabilize production in 2021. This production resiliency is a testament to the quality of our go-forward asset base and showcases the efficiencies that are driving our capital requirements lower. Currently, we are estimating that maintenance capital, which is the amount of investment required to keep our production flat will be around $1.25 billion, a 10% improvement from a year ago. With additional savings we expect from ongoing improvement in operations and natural declines, we are projecting our maintenance capital to improve to around $1.1 billion by 2021. Importantly, this improvement in maintenance capital does not assume a drawdown of our DUC inventory, which we expect to be around 100 wells by year-end. With this low maintenance capital, we are able to quickly and efficiently stem declines, and we are positioned to maintain our 2020 extra rate oil production into 2021, and should market conditions incentivize us to invest at maintenance capital levels. My final key message for today is that Devon has the right business model to maximize value for our shareholders over the long term. Admittedly, it is challenging not to get caught up in the present with today's extreme bear market conditions. But we know from experience that today's oversupply will ultimately be absorbed. When industry conditions normalize, it is our strong belief that the industry’s historic approach of creating value by prioritizing production or NAV growth will not be acceptable to investors. It is not a viable strategy to reinvest all cash flow, have high leverage, and count on OPEC curtailments to be successful. To win in the next phase of the energy cycle, we are convinced that a more balanced operating model that prioritizes additional upfront cash returns for shareholders is required. With this financially-driven model, you must moderate capital investment to deliver free cash flow yields that compete for investment with other sectors in the broader markets, have the ability to deliver margin expansion through operational scale and a leaner corporate structure, and prioritize returning more cash directly to shareholders in the form of dividends or supplemental distributions in times of windfall pricing. A successful E&P company going forward must maintain extremely low levels of leverage and not be dependent on capital markets for liquidity or funding. This critical shift in philosophy will result in a much greater margin of safety, which we all believe is needed. This balanced operating model is not new to Devon, and we have been an industry leader in this movement. Since 2018, we have deployed nearly 70% of our cash inflows towards shareholder-friendly actions, such as debt reduction, dividends, and buybacks. When industry conditions normalize, Devon is one of the very few E&P companies that will have the capabilities to deliver on this progressive cash return business model. And with that, I'll turn the call back over to Scott for Q&A.

Thanks, Dave. We'll now open the call to Q&A. Please limit yourself to one question and a follow-up. This allows us to get to more of your questions on the call today. With that, operator, we’ll take our first question.

Good morning, Dave.

Good morning, Arun.

I hope you had a good Cinco de Mayo. I have a few quick questions for you. First, could you provide more details on your leading-edge Delaware Basin well costs, which are cited at being in the low 700s? This seems to be a couple of hundred dollars per foot lower than some of the guidance we've seen from some of your Permian peers. Can you explain what is driving this lower cost figure compared to peers? Is it due to well design or other factors? Additionally, if you included facilities spending, what would that translate to on a dollar per foot basis in the Delaware?

Absolutely, Arun. I'm going to turn the call over to David Harris, our Executive Vice President of E&P, who has a lot of details around that question. But I can tell you, it's real as a result of the outstanding work that is being done by our team here, and we're not done. So, with that, I'll turn it over to David.

Good morning, Arun, and thanks for the question. Yes, we appreciate that this is a really outstanding result. It's the culmination of a lot of hard work over the last several years across our teams and disciplines. But, as Dave said, we're not done. That $705 a foot is the average cost performance that we saw in Q1. I think you're probably right to characterize it as leading edge. One of the things we've really focused on internally is a relentless drive for continuous improvement. We continue to try to turn that leading-edge performance into our P50 performance. One of the things I'd encourage you to look at, not just from a cost perspective, we also disclose our drilling and completion per foot per day metrics to provide a sense of normalized cost performance. That is really the way we try to measure ourselves—that's what we control. We don't think just presenting cost numbers, which may have some deflation in them, is the right way to hold yourself accountable and measure step-change in performance. Certainly, there's a little bit of that in ours, but our objective is to turn all those into structural change and drive those into the plan going forward, which is a big part of what you're seeing in terms of the step change in maintenance capital levels and things like that. Not just on the Wolfcamp-only performance is competitive; if you pull in our performance in all zones, not just the Wolfcamp and Delaware in the first quarter, that number is actually about $600 a foot. This isn't just about picking data points to make it look good. This is the continued quarter-over-quarter improvement that our teams have driven. To your question about the facility side, if you fully burden these pads with facilities expense, it probably pushes that average up to about $100 a foot on top of what we've disclosed there, but even with that, still well south of where we believe our peers are even without facilities in their numbers.

Great. Thanks. And just my follow-up is on the $1.1 billion of sustaining capital that you guys disclosed for 2021. I was wondering if you could help us on what type of mix that would contemplate perhaps relative to 2020? And what price signal would you need to restart completion activity for DUCs or to add incremental rig lines throughout your asset base?

Arun, that's going to be roughly 70% Delaware-type activity. We're not giving firm guidance on everything for 2021. But directionally, you can think of the activity at that level. You can see from our guide that we're really proud of how we've driven down the maintenance capital significantly. That would imply that we could have a cash flow breakeven in 2021 with somewhere around $40 WTI, which is, you just do the math, probably a 20% improvement over where we have been just in the past year or so. We are going to continue to complete wells, but at a much slower pace here for the remainder of the second and third quarters. We plan to start ramping back up with completions in the fourth quarter and then maintain more of a steady phase through 2021 if around the strip prices were to play out. David, I don't know if you have any more details on that that you'd like to hit.

No, I think you've said it well in terms of what the forward profile would look like around those kinds of assumptions. Obviously, a lot of volatility in the market, but I think that’s indicative of what we believe the business can deliver.

Great. Thanks a lot.

Thank you and good morning everyone, I hope you are all doing well. Dave, you've set a high standard this morning, and I have a couple of questions for you. First, I'd like to discuss your comments on the business model. Second, I'd like to follow up on the maintenance capital issue. If I may, I will address them together. Regarding the business model, you mentioned several points about what needs to be done to remain competitive moving forward. I'm curious about how you approach this. Is it a reinvestment rate model or a variable distribution model? How do you determine the ideal growth rate? There are many factors involved, and I’m interested in understanding if, once we emerge from this situation, there could be potential for a competitive investment case that grows at a moderate pace and capitalizes on the maintenance capital you mentioned, along with significant free cash flow. I just want to know your thoughts on this. My follow-up question is about the maintenance capital, which relates to valuation. I believe what you've disclosed recently should help the market conduct a free cash flow analysis of your business. How sustainable is the $1.1 billion in maintenance capital, and what is the underlying decline rate associated with it? So, that’s my first question regarding the business model and my second on the sustainability of maintenance capital. I appreciate your willingness to address my questions.

Yes, thanks, Doug. First, on the business model, we feel that the industry has been too focused on growth and not enough on returning value to shareholders. We think it takes a combination of higher free cash flow yield, returning cash to shareholders consistently, as well as a more moderate growth rate that would go along with that. Low financial leverage is also key; when I talk about low financial leverage, I'm talking about net debt-to-EBITDA of one or less. If there's been anything these downturns have taught us, it's that having financial strength is crucial to emerge as a strong company. We believe that the investor need to be paid along the way, and that there has to be a cash return element to this strategy that competes with other industries. The form that this cash return takes could be a combination of fixed and variable dividends, one-time dividends, or share repurchases—there are different ways to do that. We think that a cash return is vital, given the volatile nature of our industry; we can't expect investors to be active in this industry without cash returns. That’s the fundamental thinking we're operating under. To make this model successful, it's crucial to continuously drive down the breakeven costs, and that’s what we are doing. That relates to your second question about driving down the maintenance capital from $1.4 billion to $1.1 billion. It's sustainable and will keep going lower, as we will shallow out the decline curve and maintain a relentless focus on cost reduction. Whether the cost reduction comes from the capital side or expense side, we will drive those costs down, which will help with the maintenance capital investment needed. Jeff or David, do you have any additional comments?

Good morning, Doug. In terms of the decline rate, it is probably premature to give you a real specific number just given the number of potential moving parts here. As we headed into 2020, we were looking at a first-year oil decline rate probably in the high 30s. My expectation is that as we move into this more moderate spend and activity level, that will trend into the low 30s over the next year or so.

That's a very thorough answer guidance. Dave, just one quick follow-up. What do you think that organic mid-cycle or recovery scenario growth rate looks like for oil production? Are we talking 2%, 3%? 9%, 10%? Where do you see that mid-cycle?

Somewhere probably mid-single digits, around 5% plus or minus.

You gave us a lot to play with here. Thanks a lot, guys. I appreciate you taking my questions.

Thanks.

Good morning, everyone. My first question is for you, Dave. I’d like to discuss your decision regarding the suspension of shut-ins. When will you decide to bring these back? Is that decision primarily based on prices compared to cash costs? I'm curious if the thresholds you consider for each of these three are relatively similar. I understand that you've only shut in a small amount while implementing more curtailment and a slight suspension of drilling and completion. Can you clarify the thresholds you will use when bringing these back?

Good morning, Neal. This is David Harris. Regarding our curtailments, I want to remind you that out of the approximately 10,000 barrels of oil per day, we currently anticipate that around 20% will be actual shut-ins, while about 80% will involve restricting flow rates and delaying ID checks. From a shut-in perspective, we are trying to determine if we expect revenues to exceed variable costs. This evaluation will also apply when we consider bringing those wells back, so we will be cautious about reinstating the curtailments. Even though we've noticed some improvement in prices week over week, it still doesn’t seem prudent to introduce a lot of flush production into this market.

And Neal, one thing I might add is that, while we are using a similar methodology as others to determine whether to shut in or produce, it reflects the high quality of our asset base and the low operating expense we have in our key producing areas. It's not a methodology difference, but rather a reflection of the quality of our assets.

I like that clarification, David. And maybe that leads to my second question; just looking at slide eight where you talked a bit about the maintenance capital—it looks like quality is definitely improving as well. As your maintenance capital continues to come down, I guess my question is, basically, this year, I think you all are saying a little less than $1 billion can keep production relatively flat. Given that maintenance capital is coming down with your strong portfolio, would it be fair to say that you could probably keep production flat next year, probably with around the same spend as this year?

Yes, that's roughly correct.

Thank you. Good morning, gentlemen.

Good morning, Paul.

Two questions, if I may. First, on the $250 million on the cost reduction, Dave, can you guys elaborate a little bit in terms of how much of that is going to be recurring into next year? And how much is sort of one-time because you're deferring expenses or that have some temporary reduction on the compensation?

Sure. I would have Jeff Ritenour, our Chief Financial Officer, to answer that.

Paul, this is Jeff. Yes, so absolutely, a component of that $250 million is certainly variable. As you see production increase into the future, you'll see some of those costs come back as we get more active going forward. But there are also some significant pieces related to our G&A cost structure that we expect to remain permanent. We also had a severance tax credit included, which is cash in the door that we're happy to include in our 2020 results as well. So, we think it's going to be impactful for the long-term cost structure.

Jeff, do you have a number you can share to quantify what is the recurring amount?

Yes, Paul. So, roughly about $100 million of that $250 million is what we would suggest is not going to move up with additional activity in the future.

And is that all in the G&A overhead? Or is part of it in the OpEx side?

No, it's across different categories. A big component of that is your LOE, your operating cost.

Okay. The second question is that for maybe both Jeff and Dave, you have a phenomenal balance sheet compared to a lot of your peers and a lot of peer structures. When you’re looking at that, do you want to use your balance sheet as an offensive move for looking at the industry for consolidation, or do you think at this point conserving the balance sheet is more important, and you’re not trying to do too much on the consolidation side or that’s not really in the front of your mind?

That's not on the front of our mind right now. We are absolutely focused on our financial strength and liquidity. Until we understand better the depth and duration of what we're dealing with here with the demand losses leading to lower prices, we are focused on that. We recognize that we have the capability, operational capability, and organizational capability to be a consolidator, but that's not at all where we're focused right now. We are focused on coming out of this downturn as a very strong company, and we're confident we're going to be able to do it without focus on the acquisition side.

Thank you. And just a quick follow-up question: What is the minimum cash balance you guys need to run your normal operations? Thank you.

Yes, Paul. Historically, we've thought about that being around $500 million, so obviously, we’re well north of that today. If we get to a more normalized environment, that would be our expectation as something in that $500 million range.

Hi, good morning everyone. Thanks for taking the call.

Good morning.

My first question is following up on a couple of the other questions about the balance sheet and perhaps throwing some operational momentum in there. At what oil price does the 2020 plan breakeven at the asset sales? I think I heard you say earlier in the call that it was about a 20% improvement versus a few years ago, so I just wanted to clarify or get the baseline for that. If there is an outspend on strip days, can you talk about how you settled on the activity level in the second half of '20 as well as the DUC? We certainly appreciate that you're not just solving for one year, so that could require leaning on the balance sheet a bit to maintain momentum. We’re just curious to see how you see the limit on that lean and various price scenarios because you've got a really strong balance sheet, you've got good hedges, and we know that you have to factor in trade-offs between your one, then, and then year two or three plus.

Yes, Jeanine, this is Jeff. So on 2020, as it relates to our new capital program that we rolled out for $1 billion, we're obviously having the benefit of the hedges that we have in 2020. Our breakeven price now is built around kind of a $20 oil price for the rest of the year. So you've got the actuals for the first quarter, and then roughly $20 oil for the remainder of the year; that gets you to a neutral free cash flow standpoint before you get your asset sale proceeds. Regarding the second part of your question, our primary directive for 2020 was all about maintaining our liquidity through the end of the year. As mentioned, we do not have a good sense yet of the downturn's depth and duration. We wanted to maximize our liquidity so we can walk into 2021 and hopefully build operational momentum. Potentially, in the future, we might need to lean on the balance sheet a little more, but we intend not to do that for 2020. We want to maintain and frankly improve upon our cash balance and liquidity position as we go through 2020.

Great. That's very helpful. Thank you. My second question is following up on Neal's question about production curtailments. So, for the curtailments, you talked about when price exceeds variable costs, you're going to produce. So, there're other considerations; you've already run through those details. But in terms of the curtailments, why not curtail more? Do you see additional curtailments being NPV negative due to your macro view or cost of implementing them, which we've heard varying commentary on this earnings season? From other operators, we've heard that they're shutting in cash-flow-positive base production because they simply don't like the netbacks they’re seeing, and they believe in the contango in the curve; they have the balance sheet to withstand that period. So, we just want to dig into that a bit more on how you're thinking about it.

Jeanine, it's David. We're trying to maximize cash flow. To the extent that we believe that the revenues are going to exceed those costs and generate positive cash flow, we believe that's the right answer. We’ve heard some of that commentary as well, and Jeff can provide more color, but we feel comfortable with our approach. Based on the analysis we've done, you probably need a lot more contango than what we're seeing in the market today to make that math work. So whether or not that motivates others is hard for us to say, but we think we're taking the appropriate approach from a multi-year perspective.

Yes, Jeanine, this is Jeff. I would just echo David's comments; to the extent we can get revenues above that variable cost, that's incremental cash margin that offsets our fixed costs, which again, supports our primary directive of maintaining and growing our liquidity position. So, as David said, you've got to have pretty significant contango in the market to really shut-in wells for any duration. We feel, and it goes to the quality of our asset base and the low variable costs we have in our key producing basins.

We've done a lot of work on this, Jeanine. I don't know how others are thinking about it, but we'd be glad to walk you through the math. You have to remember, you're losing the cash flow of the entire barrel if you shut it in; you're only gaining the cash flow between what that well would have produced if you hadn't shut it in and what it will produce later. Given that, you've got to have a lot of contango and much more than is in the market right now to justify shutting in production from a cash flow standpoint.

Great. Thank you.

Good morning, guys. Just a question on the maintenance oil levels; does that assume that there's going to be growth in the Delaware Basin and declines elsewhere? If we think about the maintenance scenario as well, how does it look on a BOE basis? I imagine there are probably declines in gas and NGLs, but I just wanted to go over that with you.

Josh, this is David. Yes, directionally, you're right. You would expect to see a bit of decline on the NGL and gas side while holding oil flat. Year-over-year, it's probably a little bit of growth in Delaware with the other three key assets offsetting that just a bit.

Got you. And does that factor into the overall corporate decline rate you talked about in the 30s range?

Yes.

Got it. And then Jeff, you made some comments about cash on hand, the $500 million of ongoing cash. What's your thoughts on how you would look to deploy the rest of it? There are no leverage or maturity concerns right now, but your credit pricing has certainly come down over the last three months. Is there an opportunity here for you guys to start retiring some of that? Or would you just want to keep this cash on hand for the eventual recovery to kind of restart the engine here?

Yes, absolutely. I appreciate the question. Obviously, at this point, we think it's too soon to jump out there and repurchase, even though we do have some debt trading at a discount. Our intention right now is to maintain and build our liquidity through the end of the year. As we get better clarity around the depth and duration of the downturn, that will certainly be a priority on our list, as Dave mentioned, further reducing leverage. We’ll look at opportunities to jump out there and repurchase debt, and then beyond that, it will be returning cash to shareholders as we've discussed previously. We will look at different dividend strategies and potentially share repurchases at some point in the future.

Got it. And maybe just a follow-up on that. I know you earmarked the Barnett proceeds for buyback. With that pushed back into December, is there any thought about opportunistic buybacks with the stock at this price? Or does that kind of get pushed into 2021 now?

No, absolutely not. We've suspended the stock repurchase program given the current environment, to protect our liquidity, so we won’t have any share repurchases for the remainder of this year.

Great. Thanks, guys.

Good morning and thank you for taking my question. My first question is around the capital efficiency and operational efficiency you talked about in the Wolfcamp. As you slow down activity, is there a risk that you could see some of those operating efficiencies come down? Or have you already accounted for those?

No, we don't think that's a big risk. I think that’s part of how we've approached this—determining that the current activity level is right for us. So no, we feel like we can continue to not just maintain the efficiency you're seeing, but we believe we can continue to drive it forward. And while we focused a lot on the cost side, remember that the capital efficiency piece also has a productivity component in there. You’ve seen our productivity results from our wells not just in the Wolfcamp but across the Delaware and the rest of the portfolio—those are competitive across the industry. We're not just trying to cut costs at the expense of jeopardizing productivity. We will continue to focus on both sides of that equation to maximize results going forward.

Got it. Thank you. David, I certainly appreciate your comments early on about the change in the business model. What role do DUCs play in your 2021 program? You talked about moderate single-digit growth. I’m curious because 100 DUCs is probably not the right level for the amount of capital you're spending. How do you plan to deploy those DUCs for 2021? Is it for growth or something else?

No, we feel that the 100 DUCs are essentially just a good working level of DUCs given our activity levels. We believe that the 100 DUCs will allow us the ability to restart the business quickly since we're not drawing those down. That is another reason we feel good about moving into 2021.

Okay. Thank you for answering my questions.

Good morning. First question, I was wondering if you could rank order the plays after the Delaware Basin that will attract capital when the time is right. I thought the PRB results were quite impressive, particularly the Teapot wells. That zone has not received much discussion compared to the Turner, the Parkman, or Niobrara industry-wide.

Thanks for the question. It’s difficult to give you a rank order today, as it depends heavily on gas and NGL prices. We've got a lot of optionality in the stack. You're right—the Powder results in the Teapot have been impressive and continue to have a low breakeven cost. One of the things we've highlighted that, that basin our highest margin asset in the portfolio for the quarter. It’s a high oil cut with light, high-quality oil that we think is very desirable. It has a lot of torque to higher prices. Let's not forget the Eagle Ford; we’ve got exciting redevelopment and infill potential there, which will extend the life and yield highly competitive economics. All three have mixed oil, gas, and NGL components, making them attractive for the future. But, I can't give you a rank order; it will depend on broader market conditions.

Okay, that's fair. I appreciate that. Just a follow-up on a prior question; when you say that you can accelerate the 2021 activity DUC portfolio that you'll have at year-end 2020, is that still consistent with the long-term approximately 5% growth target that you've laid out as part of your business case going forward?

Yes. I don’t think we intend that to diverge from Dave's comments around what we believe the appropriate growth rate for the industry and for Devon likely is. That being said, it will give us good flexibility and optionality as we think about how to restart and at what pace.

Okay, great. Thank you.

Thank you. Good morning. To follow up on a couple of the earlier questions, what would be the key price point that you would need to see before moving from maintenance capital back to growth mode? And do you need to see leverage drop below one times before moving to that mid-single-digit growth, or is sub-one times leverage a function of mid-single-digit growth?

Hey Brian, yes, this is Jeff. Our absolute priority would be to reduce leverage going forward and get to that one times net debt or lower on that net debt to EBITDA ratio. That is going to be top of mind as we move. The growth rate for us is an output of the inputs. We think about our business; number one, ensuring that we have financial flexibility and strength, highlighted by our net debt to EBITDA target as one measure we look at. We're committed to running the business to be at least neutral on free cash flow on an ongoing basis. That growth rate will ultimately result from the capital we deploy in each growth area constrained by those bigger-picture financial objectives.

Got it. Should we think of maintenance mode as continuing until we see a sub-one times leverage?

I wouldn't pin it down to needing that specific metric before we would accelerate any activity. Again, it's going to be a function of all the different price dynamics we're seeing in the market, the shape of the curve, comfort with sustainability long-term, and the ability to hedge. Many variables will factor into that calculus before we determine what increased activity looks like.

Brian, directionally, I’d say you probably need to think in terms of a sustainable $40 to $45 WTI before we would go out of maintenance capital mode and start looking at growth again.

Great. Thank you. When you discuss the success you're having in lowering your costs in the Permian and the Wolfcamp as well as the maintenance capital, how much of that do you attribute to either processes unique to Devon, or the assets, or is it indicative that there's more potential for the industry to push supply costs lower across the Permian Basin in particular?

Brian, this is David. We have a lot of confidence that it's our assets and the high level our teams are performing at; I can't emphasize that enough. The execution you're seeing is the result of seamless integration across multiple disciplines driving that cost result. We believe our cost performance relative to what others are doing in the industry is highly unique to us. Coupling that with what we think are best-in-class assets, that gets you to a very differentiated result. I believe there's potential for the entire industry to improve, but we’re convinced we’ll be even better than that in the end.

I believe there's potential for the entire industry to improve, but we’re convinced we’ll be even better than that in the end. That’s alright.

Great. Thank you.

Good morning Dave to you and your whole team there.

Good morning, Charles.

I appreciate the detailed explanation you've provided on your curtailments. However, could you share more about how it unfolds over time? Specifically, how much of the second quarter curtailment is already accounted for in April? What are your projections for May, and what is your plan for June? Will it differ from May?

Charles, this is David. The number we've given you reflects decisions we've made for April and May. Those decisions were made and we have forecasted out for the quarter. For production in June, those decisions will be made in the next couple of weeks. It's hard to predict; it feels better than it did last week, but there has been a lot of volatility in the market, which makes it difficult.

Hey, Charles, this is Jeff. To David's comments, as we look to June, we've seen prices firming up on both the roll and the calendar month average. Our marketing teams have worked closely with the business unit teams to get out in front of the markets we’re seeing. Right now, based on current sentiments, we don’t see significant incremental shut-ins or curtailments.

Got it. Yes, let’s hope it keeps getting better. And then my follow-up, on the Barnett close, the sale of that or the closing of that deal. You mentioned you're on track. What are some of the signposts we should look for along that track as we go through the rest of the year?

Hey, Charles, this is Jeff. I would say the first piece, which is important, is the incremental deposit we received. So we've already collected $170 million from our counterparty. Moving forward, there's not a lot left to get done. The teams are working diligently removing all the responsibilities we have related to the contract to move us towards close. We feel good about that and look forward to closing by year-end.

Well, it looks like we've made it through all of our questions in the queue today. I appreciate everyone's interest in Devon. If you have any further questions, feel free to reach out to the Investor Relations team at any time. Thank you for your interest.