Devon Energy Corporation (NYSE:DVN) Q1 2020 Earnings Conference Call May 6, 2020 10:00 AM ET
Scott Coody - VP, IR
Dave Hager - President and CEO
Jeff Ritenour - CFO
David Harris - EVP, Exploration and Production
Conference Call Participants
Arun Jayaram - JPMorgan
Doug Leggate - Bank of America
Neal Dingmann - SunTrust
Paul Cheng - Scotiabank
Jeanine Wai - Barclays
Josh Silverstein - Wolfe Research
Nitin Kumar - Wells Fargo
Jeffrey Campbell - Tuohy Brothers
Brian Singer - Goldman Sachs
Charles Meade - Johnson Rice
Welcome to Devon Energy's First Quarter 2020 Earnings Conference Call. At this time, all participants are in a listen-only mode. This call is being recorded.
I would now like to turn the call over to Mr. Scott Coody, Vice President of Investor Relations. Sir, you may begin.
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 timing or wide range the impact of this pandemic to 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 effectively navigate through these challenging times. Adding to these competitive advantages is our talented team here at Devon.
And 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 during this unprecedented time 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, 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 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 is not mature until the end of 2024. This facility contains only one material financial covenant, a debt-to-capitalization ratio below 65%.
And 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. And lastly, a key event that will be 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 of total proceeds, consisting of $570 million in cash at closing and contingent payments of up to $260 million.
This agreement includes this $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. And 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 further 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 and a decline of 45% compared 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 effectively 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 to continue to optimize the organization's overhead. This includes an expected 40% reduction in cash compensation for our executive management team year-over-year.
I want to reinforce that 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 challenging -- 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% to 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. And 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 regards 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 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 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 were 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 know 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 advantage 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 stack 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 the 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 have expectations for 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 as well as shower based declines, we are projecting our maintenance capital to improve 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.
And 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 a 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 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, prioritize returning more cash directly to shareholders in the form of dividends or supplemental distributions in time of windfall pricing, and 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. And 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.
Your first question from the line of Arun Jayaram with JPMorgan.
Good morning Dave.
Good morning Arun.
I hope you had a good Cinco de Mayo, but a few quick questions for you. One, I was wondering if you could provide a little bit more details on your leading-edge Delaware Basin well costs, which is cited at being in the low 700s. This looks to be a couple of hundred dollars per foot lower than some of the guides we've seen from -- some of your Permian peers.
Can you talk about what is driving this lower cost figure relative to peers? Is this well designed or other factors, and I wanted to see if you could provide some details on -- if you included facilities spend, 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, I think has a lot of details around that question. But I can tell you, it's real as a result of 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, across disciplines. But as Dave said, we're not done. And so, 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, but one of the things that we've really focused on internally, there's really a relentless drive for continuous improvement. And so, we continue to try to turn that leading-edge performance into our P50 performance.
So, 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 try to give you a sense on a normalized for cost basis what the performance looks like, and so that's really the way that we try to measure ourselves, that's what we control.
We don't think just presenting cost numbers, that may have some deflation in them. It is the right way to really 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 I think is a big part of what you're seeing in terms of the step change in maintenance capital levels and things like that.
And so, not just as that Wolfcamp-only performance, really competitive -- exceeding, as you said by a couple of hundred million dollars, other peers in Delaware, if you look at the performance, if you pull in our performance in all zones, not just the Wolfcamp and the Delaware in the first quarter, that number is actually about $600 a foot.
So, this isn't a function of just picking a couple of data points and trying to make to make it look good. This is the continued quarter-over-quarter improvement that you are seeing the teams really do a great job at driving.
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 or $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?
A – David Hager
Arun, that's going to be roughly 70% Delaware-type activity. We're not giving firm guidance on everything on 2021. But directionally, you can think of the activity in that level. You can see from our guide that we have there 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, it's probably a 20% improvement of 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 second quarter and the third quarter. We plan to start ramping back up with completions in the fourth quarter and then maintain more of a steady phase through 2021 if something 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.
Your next question comes from the line of Doug Leggate with Bank of America.
Thank you and good morning everybody, and I hope everybody is doing well out there. Dave, you've pretty set the bar pretty high, we think, this morning. I want to ask you a couple of things. One, about your comments on the business model. And two, to follow-up on the maintenance capital issue. So if I may, I'll do them back-to-back.
The first one is the business model, you made a number of comments there about what you need to do to compete coming out the other side of this. So, I just wanted to poke a little bit on that. And explore things like how do you set -- how do you design that? Is that a reinvestment rate model? Is that a variable distribution model?
How do you think about the ideal growth rate? There's a lot of things go into that, and I'm just wondering, when we come, assuming we come out the other side of this, there is the potential to be of a very competitive investment case that grows at a moderate pace and really builds on that maintenance capital that you talked about with a lot of free cash flow. I just want to know how you think about that.
My follow-up is on the maintenance capital, and it really gets to the issue of valuation because I think what you've disclosed recently and again last night, should allow the market to at least put a free cash flow analysis around your business.
My question is, how sustainable is that $1.1 billion, and what is the underlying decline rate that goes along with that? So, the first one in the business model, and the second one, the sustainability of the maintenance capital. And I appreciate you taking 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, and we think it takes a combination of higher free cash flow yield, returning cash to shareholders in a consistent manner, as well as a more moderate growth rate that would go along with that.
And then third, low financial leverage, and when I talk about low financial leverage, I'm talking about net debt-to-EBITDA of one or less. And I think if this has taught us anything that we've had three downturns in the past 11 years. And you can say they're all unrelated going back to 2008 or the 2014, 2015, 2016 time frame and now these, but you may call them unrelated, but there's been three regardless of how you look at it.
And so I think that it is absolutely important to have financial strength coming into these so that you can emerge as a strong company. And that's the attitude that we had coming into this and is paying off extremely well. I think that the invest is just so important that the investors need to be paid along the way. And there has to be a cash return element to the strategy that competes with other industries.
Now, the form of which that cash return takes place, we're flexible on. It could be a combination of fixed and variable dividend. It could be one-time dividends. It could be share repurchases. There's different ways to do that, and we're open-minded on how that might take place.
But we think that a cash return is just so much more important, given the volatility in our industry, we can't expect investors to be active in this industry if they aren't getting returned to cash along the way. So that's kind of the fundamental thinking of how we are doing it.
And to make that model successful, you have to continuously drive down the breakeven costs associated with your company. And that's what we're doing, and that's really leads to your second question, which is the driving down of the maintenance capital from $1.4 billion to $1.1 billion.
It's not only sustainable, but it's going to continue to go lower, because we're going to, through time, be shallowing out the decline curve. We also be a relentless focus on cost reduction.
Whether the cost reduction comes on the capital side capital side or the expense side of the equation, we're going to be driving those costs down and as we drive those down, that obviously is going to help out with the maintenance capital investment that's required. So Jeff or David, I don't know if you have any additional comments that -- don't have? But David?
Good morning, Doug. To your specific question around the decline rate, probably premature to give you a real specific number just given the number of potential moving parts here -- as we go throughout the year, but the level set you. You know, as we headed into 2020, we were looking at a first year oil decline rate probably in high 30s.
And so certainly would be my expectation as we move to this more moderate spend and activity level, that you absolutely ought to see that decline rate trend into the low 30s here 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? Oil production? Where -- 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. Appreciate taking my questions.
Your next question on line of Neal Dingmann with SunTrust.
Good morning, all. My first question, Dave, just really centers on your shut-ins curtailment suspension. Just wondering, is the decision -- when you decide to bring these back? Is that just simply based on prices versus cash cost?
And if so, I'm just wondering, are the thresholds when you sort of look at each of these three, I mean, looking at I know you've just sort of shut in a very minimal amount and with more curtailment and a bit of suspended D&C. I'm just wondering, when you bring these back, are these the threshold for each of these about the same?
Good morning, Neal. This is David Harris. You know from the standpoint of our curtailments, I'd remind you that of the approximately 10,000 barrels of oil a day, we currently expect to have curtailed about -- about 20% of that would be actual shut-ins and about 80% would be restricting flow rates and pushing IDs back.
And so as you know, particularly from a shut-in perspective, we're trying to ascertain whether we believe the revenues are going to exceed the variable cost. And so -- that analysis would hold -- as you look just to potentially bring those wells back on. So kind of the same analysis that we do going in. We'll do coming back out in order to determine when the right time to bring those shut-in wells back on.
I would say in terms of the curtailment bucket, in terms of restricted flowbacks and things like that, we're probably going to air on the side. You know, even though we've seen a bit of improvement here, week over week in prices still doesn't feel like the right thing to do to push a bunch of flush production even into this kind of market. So I would expect you'll see us be fairly conservative on that front.
And Neal, one thing I might add, you didn't ask, but I'll put it in there for context. With the -- I suspect that we are using a very, very similar methodology for determining whether to shut-in as other people in the industry when the revenue does not exceed the variable expense of producing those variables.
What this really shows is the high-quality of our asset base, the high-quality of those barrels. And in addition, the very low operating expense that we have in our key producing areas. And so it's not a methodology difference. I don't believe at all, but is a reflection of the quality of our asset position, which I think is important not only to consider for shut ins, but to think about the quality of the assets that underpinned the success of -- the future success of the company.
I like that clarification, David. And maybe that leads to my second. Just looking at slide eight where you all talked a bit about, which I think is a very good slide, by the way, and talks about the maintenance cap, given it looks like the quality is definitely filing there as well.
As your maintenance cap continues to come down. I guess my question is, basically, this year, I think you all are saying a little less than $1 billion or so, you can keep production relatively flattish.
And with maintenance, obviously coming down given now the strong portfolio, I know you don't have 2021 production guide out there, but it would look to me that given this is still both the maintenance cap coming down, you could probably still keep production rather flattish next year, probably with around the same spend this year. Is that fair to say it.
Yes, that's roughly correct.
Okay. Very good. Thank you all.
Your next is from the line of Paul Cheng with Scotiabank.
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 a one-time because you're deferring expense 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. And so as you see production increase into the future, you'll see some of those costs come back as we get more active into the future.
But there's also some very significant pieces related to our G&A cost structure and otherwise, that we expect to be permanent going forward. So you also had a severance tax credit in there, which is cash in the door, which we're happy to include that in our 2020 results as well.
So going forward, 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 yes, so roughly about $100 million of that $250 million is what we would suggest is not going to move up with additional activity into the future.
And is that all in the G&A overhead? Or is part of them in the OpEx side?
No, it's across all 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 structure. And so when you're looking at that, do you want to use your balance sheet as an offensive move and looking at the industry for consolidation as a consolidator or that you think at this point, conserving the balance sheet is more important and you were 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 absolutely focused on that.
We recognize that we have the capability, operational capability, the 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 and no focus on the acquisition side right now.
Thank you. And just a quick sign question. What is the minimum cash balance you guys need to run your normal operation? Thank you.
Yes Paul. Historically we’ve thought about that been around $500 million, so obviously we’re well north of that today, but if we get to more of a normalized environment, that would be our expectation as something in that $500 million range.
Our next question comes from the line of Jeanine Wai with Barclays.
Hi, good morning everyone. Thanks for taking the call.
My first question is following up on a couple of the other questions about balance sheet and maybe 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; it was about a 20% improvement versus a few years ago. So just wanted to clarify or get the baseline for that.
And 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 and the DUC? We can like certainly appreciate that you're not just solving for one year. So that could require leaning on the balance sheet a little bit to maintain momentum.
And so 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 kind of trade-offs between your one and then and then year two, three plus.
Yes, Jeanine, this is Jeff. So on 2020, as it relates to our -- the new capital program that we rolled out for at $1 billion, we're obviously having the benefit of the hedges that we have in 2020. But our breakeven price now is -- we built the program 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, and that gets you kind of to a free cash flow neutral standpoint before you get your asset sale proceeds.
And then going forward, the answer the second part of your question, we really -- our primary directive for 2020 was all about maintaining our liquidity through the end of the year.
Obviously, as Dave described earlier, we don't have a good sense yet of the depth and duration of the downturn. So we wanted to make sure we maximized our liquidity through the remainder of 2020, so that we can walk into 2021 and hopefully build upon our operational momentum.
And potentially, in the future, we might, to your point, have to lean on the balance sheet a little bit more. But our intention for 2020 is not to do that. So we want to maintain or, frankly, improve upon our cash balance and liquidity position as we work 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 exceed variable costs, you're going to produce. And so, there are kind of other considerations that you already ran through about leases and other things.
But in terms of the curtailments, why not curtail more do you see additional curtailments as being NPV negative given either your macro view or the cost of implementing them, which we've heard varying them, which we've heard varying commentary on what that is this earning season.
And we've heard some commentary from other operators that they're shutting in cash flow positive base production because they just simply don't like the netbacks are seeing and they believe in the contango in the curve and they've got the balance sheet to kind of withstand that period, and Devon has a very strong balance sheet, too. So we just wanted to kind of dig into that a little bit more on how you're thinking about it.
Janine, it's David. Yes, I think from our standpoint, look, we're -- first of all, you start with flow assurance, right? You got to make sure you can move the molecules. We feel really good about that. Then you turn to that economic analysis that you described.
And from our perspective, our objective is to maximize cash flow. And so 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. Jeff can chime in here and give you more color.
But I think what we would suggest to you is based on the analysis we've done you probably need a lot more contango than you see in the market today to really make that math go around. And so whether or not that's really a motivating other people's decisions or not, it's hard for us to say. But we feel comfortable with the approach we've taken. We absolutely believe it's the right answer from a multiyear perspective.
Yes. Jeanine, this is Jeff. I would just echo David's comments. From our standpoint, to the extent we can get revenues above that variable cost, that's incremental cash margin that offsets our fixed cost, 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 sort of duration. So we feel -- and again, it goes to the comment that Dave made earlier in the call, it goes to the quality of our asset base and the low fixed cost or excuse me, variable costs that we have in each of our operating basins.
We've done a lot of work on this Jeanine. And I don't know how others are thinking about it, but be glad to walk you through the math that we've done with it. But I think that you have to keep yourself in mind, you're losing the cash flow of the entire barrel if you shut it in, and 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, given the pack you had shut it in.
It's not the entire barrel you get back. It's just the incremental difference between those two numbers. And so you got to -- so given that, you've got to have a lot of contango and much more than is in the market right now to make that make economic sense from a cash flow standpoint.
Great. Thank you.
Your next question on the line of Josh Silverstein with Wolfe Research.
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? And then if we were to think about the maintenance scenario as well, how does it look like on a BOE basis? I imagine there's probably declines in gas and NGLS but I just wanted to go over that with you.
Josh, this is David. Yes, I think directionally, you're right. I think you would expect to see a bit of decline on the NGL on the gas side to hold that oil flat. Year-over-year, it's probably a little bit of growth in Delaware with sort of the other three key assets offsetting that just a little bit.
Got you. And was that factor into the overall kind of corporate decline rate you were talking about in the 30s range?
Got it. And then Jeff, you made some comments before about the cash on hand, the $500 million of ongoing cash. What's your thoughts on how you would look to deploy, I guess, the rest of it.
There's no leverage or maturity concerns right now, but your credit pricing has certainly come on down over the course of 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. No, absolutely. I appreciate the question. Obviously, at this point, we think it's too soon to jump out there and repurchase that even though we do have some issues trading at a discount.
Our intention at the moment is to maintain and build upon our liquidity through the end of the year. As we get better clarity around the kind of the depth and duration of the downturn, that is absolutely something that will be on the top of our priority list, as Dave mentioned earlier, which is to further reduce leverage.
So, we'll look at opportunities to jump out there and repurchase debt. And then beyond that, it's going to be returning cash to shareholders as we talked about in the past. So as Dave mentioned, we'll 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. And with that now push back into December, is there any thought about opportunistic buybacks with the stock in at this price? Or does that kind of get pushed into 2021 now?
No, absolutely not. No, we've suspended the stock program, stock repurchase program, obviously, given the current environment to, again, protect our liquidity and so we won't have any -- we don't expect to have any share repurchase for the remainder of this year.
Great. Thanks guys.
Your next question from the line of Nitin Kumar with Wells Fargo.
Good morning and thank you for taking my question. My first question is just around the capital efficiency, the 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 looked at the different variables and thinking about why the current activity level is the right level for us.
So no, we feel like we can continue to not just maintain the level of efficiency you've seen, but continue to drive it forward. And the one thing I would remind you, I mean, we've talked a lot about the cost side of the equation this morning. And certainly, that's important.
Remember that the capital efficiency piece has also got a productivity component in there. And so you've seen our productivity results from our wells, not just in the Wolfcamp, but across the Delaware and the rest of the portfolio.
Clearly, those are competitive with what we think anything -- anybody is doing in the industry. And so we're not just trying to cut costs at the sake of -- at the risk of jeopardizing productivity. We're going to continue to focus on both aspects of that equation to maximize that result going forward.
Got it. Thank you. And David, I certainly appreciate, I think investors appreciate your comments early on about the change in the business model. What 100 DUCs play in your 2021 program? You talked about very moderate single-digit growth. I'm kind of curious because 100 DUCs is probably not the right level for the amount of capital you're spending. So just curious, how do you plan to deploy those DUCs for 2021? Is it for growth or something else?
No. I would -- we feel that, the 100 DUCs are essentially just a good working level of DUCs given our activity levels. And so the point, we're trying to make is that we have not included the drawdown of those DUCs to show what our maintenance capital, as I think some other companies have talked about that fact, frankly, that they say park when they calculate maintenance capital.
That they are including, draw down of DUCs which we think is not really matches what the actual definition of maintenance capital. It should just include a more static level that is consistent with the ongoing business.
Now, the 100 DUCs is going to allow us absolutely the ability to restart the business very quickly, since we're not drawing those down. So that is another reason, and we feel good about moving into 2021.
Okay. Thank you for answering questions.
Your next question in the line of Jeffrey Campbell with Tuohy Brothers.
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 that PRB results were quite impressive, particularly the Teapot wells and zone has not gone a lot of discussion versus the Turner, the Parkman of Niobrara industry-wide.
Thanks for the question. I would say, it’s a bit difficult to give you a rank order today, a lot is going to depend on gas and NGL prices. We've obviously got a lot of optionality in the stack out there. You're exactly right. The powder results in the Teapot have been impressive continue to have a really low breakeven cost.
One of the things we highlighted that, that basin our highest margin asset in the portfolio for the quarter. It's a high oil cut. It's a light high-quality oil that we think is really desirable. So it's got a lot of torque to higher prices. And don't forget the Eagle Ford, we've got a lot of exciting stuff going there from a redevelopment and an infill perspective that, we think is going to meaningfully extend the life of really highly competitive economic work to do there.
And so across those three they all have a little bit of a mix from an oil, gas and NGL perspective. So we like all three of them. We think all three of them have an important place in the portfolio going forward, but a rank order really going to depend on what kind of assumptions you want to make across the three streams.
Okay, that's fair. I appreciate that. And just a follow-up on a prior question, when you say that you can accelerate the 2021 activity DUC portfolio that you're going to have in hand at this yearend 2020. Is that still consistent with this -- I'm talking about acceleration. Is that still consistent with the long-term approximately 5% growth target that you've laid-out as part of the business case going forward? Thank you.
Yes. Certainly. I don’t think we intend that, that to diverge from Dave's comments really around what we believe the more appropriate growth rate for the industry and for Devon likely is, I do think it does give us in a pretty volatile environment, some good flexibility and optionality as we think about how we want to restart those and at what pace.
Okay, great. Thank you.
Your next question in the line of Brian Singer with Goldman Sachs.
Thank you. Good morning. To follow-up on a couple of the earlier questions, what would be the key price point you would need to see before moving from maintenance capital back to growth mode and do you need to see leverage go sub one times before moving to that mid-single-digit growth or a sub one times leverage a function of mid-single-digit growth?
Hey Brian, yes, this is Jeff. Yes, as we said before, our absolute priority would be to reduce leverage going forward and get to that one times net debt -- or frankly, lower on that net debt to EBITDA ratio. So, that's going to be in the front of our mind as we move.
And again, the growth rate for us is an output of the inputs, right? As we think about our business, number one, ensuring that we have the financial flexibility and strength that we want. We've highlighted that with that net debt to EBITDA target as one measure that we look at.
We're committed to running the business to be at worse neutral on free cash flow on a go-forward basis. And then that growth rate will ultimately fall out of the capital that we spend, obviously, in each of our different growth rate will ultimately fall out areas, constrained by those bigger picture financial objectives.
Got it. So, should we think of maintenance mode as continuing until we see a sub one times leverage show up?
I wouldn't -- no, I don't think I would pin it down to -- we have to have that sort of metric before we would accelerate any activity. Again, it's going to be a function of all the different price dynamics that we're seeing in the market, the shape of the curve, how comfortable we feel that that's sustainable; longer term, our ability to hedge. So, as you know, there's a bunch of different variables that will go into that calculus before we determine what increased activity looks like.
Brian, directionally, I would 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. And then my follow-up is, when you talk and highlight the success you're having in lowering your cost in the Permian and the Wolfcamp as well as the maintenance capital, how much of that do you attribute to either the process that's unique to Devon, the assets or is it just indicative that there's more widespread potential for the industry to push supply cost down across the Permian Basin in particular?
Brian, this is David. I think from our perspective, I think we have a lot of confidence that it's our assets and it’s the high level that our teams are performing at. It can't be noted enough. I think the execution you're seeing is the result of a lot of really seamless integration across multiple disciplines that are driving that cost result.
And so I think from our perspective, if you look at the sort of costs that we're putting up relative to what you're seeing from others. Certainly, we feel like that is highly unique to us. And you couple that with what we believe are best-in-class assets and that gets you to what we think is a really differentiated result.
I think there's a potential for the whole industry to get better, but that's okay. We'll be even better than that at the end. So, that's all right.
Great. Thank you.
And your next question in the line of Charles Meade with Johnson Rice.
Good morning Dave to you and your whole team there.
Good morning Charles.
So, I -- you guys have talked a lot about your curtailments and I appreciate the real detailed explanation you've given on your process. But I'm wondering if you could add some detail about decompose it along the time line. In other words, how much of that 2Q curtailment, have you already -- is already in the books in April? And what are you expecting for May? And what's the plan for June? Does it look different from May?
Charles, this is David. The number that we've given you reflects decisions we've made for April and May. So those are things that that we've already done and we have forecasted out for the quarter. For the production month of June those decisions will be made here over the next couple of weeks. And so it's hard to -- it feels better than it did last week, but it's hard to predict just given the amount of volatility we've seen in the market, what exactly June will look like in terms of the decisions we make.
Hey, Charles, this is Jeff. I would just add, though, that to David's comments that as it relates to June, obviously, we've seen prices firm up on both the roll and the calendar month average. And our marketing teams along with the business unit teams have worked really closely together and done a great job kind of getting out in front of what we're seeing in the market. And so, at this point in time, as David said, things can and have changed quickly over the last several months on a day-to-day basis, but at this point in time, we don't see a significant incremental amount of shut-ins or curtailments at this point.
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 close of that deal. You mentioned you're on track. What are some of the signposts that we should look for along that track as we go through rest of the year?
Hey, Charles, this is Jeff. I would say the first piece, which is important was the incremental deposit that we got in the door. So we've already collected $170 million of deposit from our counterparty there. And then going forward, frankly, there's not a lot.
I mean, as we work forward to the end of the year, the teams have done a great job of taking off all the responsibilities that we have related to the contract to move us towards close. So we feel really good about that and look forward to getting to close 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. And if you have any further questions, feel free to reach out to the Investor Relations team at any time. Thank you for your interest.
Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.