Parsley Energy, Inc. (NYSE:PE) Q1 2020 Earnings Conference Call May 5, 2020 9:00 AM ET
Kyle Rhodes - VP, IR
Matthew Gallagher - President, CEO & Director
David Dell'Osso - EVP & COO
Stephanie Reed - SVP, Corporate Development, Land & Midstream
Ryan Dalton - EVP & CFO
Conference Call Participants
Scott Hanold - RBC Capital Markets
John Freeman - Raymond James & Associates
Jeanine Wai - Barclays Bank
Brian Singer - Goldman Sachs Group
Charles Meade - Johnson Rice & Company
Michael Hall - Heikkinen Energy Advisors
Brian Downey - Citigroup
Leo Mariani - KeyBanc Capital Markets
Neal Dingmann - SunTrust Robinson Humphrey
Joshua Silverstein - Wolfe Research
Asit Sen - Bank of America Merrill Lynch
Jeffrey Grampp - Northland Capital Markets
Gail Nicholson - Stephens Inc.
Phillips Little - Capital One Securities
Gabriel Daoud - Cowen and Company
Good morning, ladies and gentlemen. Welcome to the Parsley Energy's First Quarter 2020 Earnings Call. My name is Shamali, and I will be your operator today. As a reminder, this call is being recorded. [Operator Instructions].
And now I'm pleased to turn the call over to Kyle Rhodes, Parsley Energy's Vice President of Investor Relations.
Thank you, Operator, and good morning, everyone. We are dialing in from our respective home offices this morning. With me on the call are Matt Gallagher, President, and CEO; David Dell'Osso, Chief Operating Officer; Ryan Dalton, Chief Financial Officer; and Stephanie Reed, Senior Vice President of Corporate Development, Land and Midstream.
Our remarks today may contain forward-looking statements. So please see our earnings release for a discussion of these statements and associated risks, including the fact that actual results may differ materially from our expectations. We also make reference to non-GAAP measures, so please see the reconciliations in the earnings release.
During this call, we will refer to an investor presentation that can be found on our website, and our prepared remarks will begin with reference to Slide 3 of that presentation. After our prepared remarks, we'll be happy to take your questions. And with that, I'll turn the call over to Matt.
Thanks, Kyle. It's been just over 10 weeks since we hosted our fourth quarter earnings call. But in some ways, it feels like 10 years. The COVID-19 pandemic carries with it a steep cost, both socially and economically, the full extent of which likely won't be tabulated for some time to come.
For the energy industry, specifically, COVID-19 has caused unparalleled global oil demand destruction, resulting in a sharp drop in near-term oil prices. In this time, I need to commend our own heroes, our field operators, and our contractors, and our vendor partners, whose work continues to provide domestically-sourced energy day in and out, albeit in a modified process, due to the virus. Parsley took swift action in response to the virus and appending oil demand shut all focused on the health of our employees and the health of our business.
Turning to those business results. I want to acknowledge some accomplishments by our team that would have normally received the lion's share of attention in a typical quarter. First, after closing our Jagged Peak acquisition in early January, the integration process has been seamless. This is a testament to rigorous planning, collaboration and behind the scenes effort from numerous departmental groups, truly a team effort. This is partially at its best. Synergy capture is well in hand.
Next, I want to highlight our drilling, completions, and facilities teams for continuing to grind well costs lower, while safely pushing efficiencies higher. David will touch on the continuous organic improvements recorded by our team a bit later. Finally, I would be remiss for not mentioning the strides taken on multiple fronts year-to-date to reinforce the strength of our balance sheet. In these challenging times, strong financial footing is paramount.
With that, let's turn to Slide 4. The world changed quickly over these past 2 months and partially responded in kind, taking decisive action on multiple fronts. Oil prices will recover, but there is no crystal ball as to when. Parsley is well built for the endurance test now facing the industry. We will remain focused on controlling what we can control. And as you can see in the timeline, Parsley's responsiveness has truly been collective in nature, spending multiple disciplines across our organization. These coordinated efforts all have the same goal in mind to protect the long-term resiliency of our business model. The Parsley team is highly engaged and utilizing our solutions-driven mindset, the agile corporate structure to navigate this environment.
Turning to Slide 5. One key advantage of the short-cycle capital projects delivered by Parsley and other domestic shale producers is that activity and spending plans can quickly adapt to changing market conditions. We started this year budgeting at $50 oil with a capital budget of $1.6 billion to $1.8 billion. We were running 15 rigs and 5 frac crews during January and February but steadily reduced activity throughout March as oil prices and market fundamentals deteriorated. In mid-April, we temporarily suspended sanctioning all new drilling and completion operations. Our 2020 activity plans will remain flexible, and our capital allocation philosophy will remain simple. We will not build through our hedge book, but we'll evaluate incremental capital investment decisions based on unhedged economics and prevailing market conditions.
The table at the bottom left of the page describes our near-term plans for the second quarter, characterized in the shutdown sensitivity, and also lays out our stabilized activity plan. A greatly reduced activity level versus our original long-range planning allows for even further high grading of projects based on rates of return. As things sit today, we are now budgeting at $20 to $30 oil for the remainder of the year and plan to spend less than $700 million in capital in our stabilized activity model, the majority of which was sent during the first quarter.
Turning to Slide 6, where we demonstrate the shape of the production under our current plan and also under a more draconian scenario. The dark blue wedge represents that scenario, which would be a full capital shutdown. No new wells placed on production. In effects, this is a PDP blowdown case. The lighter blue wedge represents our current plans to reactivate to a stabilized activity level, popping completed wells, completing DUC wells, and reestablishing a baseline development activity running 4 to 5 rigs and 1 to 2 frac crews. Both cases yield healthy free cash flows and moderating declines, which positioned our company to be on solid footing for years to come.
Of note, you will see we are voluntarily curtailing May production to the tune of about 25%. This is a choice. 5 weeks ago, we saw demand data pointing to an unparalleled demand shock. 5 weeks ago, we saw data pointing to storage levels, increasing on a global level at rates seen during Hurricane Harvey at a local level. We asked for the Texas Railroad Commission to have a hearing for a proration order. They had a robust debate with over 10 hours of testimony. Today, it appears that no action will be taken by the commission. Parsley was in a position to make a choice about how to manage our volumes, and that choice is clear for us, but some other operators had no choice. Some independent oil producers who are having purchasing contracts canceled and pulled out from under them. Yet others, not due to market conditions or market signals, who are producing at maximum rates to fulfill pipeline commitments or other obligations, compounding a near-term problem.
Disproportionately, the 1000s of truly independent oil producers were in gridlock. Parsley was started by a small number of value-minded people, and we grew this company from scratch investing our own money and with great partners along the way in the private days. Most of those in support of proration, like us, started with 2 to 3 people and put their own capital at risk. We often remind ourselves to act as we did in those days, when we looked at every dollar in and every dollar out and didn't just bet on greener pastures. The choice is clear for near-term curtailment. Currently, the world does not need more of our product, and we only get one chance to produce this precious resource for our stakeholders.
We will be closely evaluating conditions for June. With our current visibility, we see at maximum repeating May curtailments. But if our full realizations return at this current strip, we will follow the shape as listed on Slide 6. We have also provided a glimpse of what maintenance capital program would look like in 2021. In short, the treadmill is slowing down, making it easier to turn cash flow into free cash flow. For example, in the stabilized activity scenario, we estimate it would take only $600 million to hold fourth quarter 2020 oil production flat for the subsequent year.
In both scenarios, we expect to generate healthy amounts of free cash flow in 2020 to the tune of $300 million-plus and exit the year with a solid balance sheet, ample scale, and a shallower oil-based decline, and visibility to sustained free cash flow in 2021. Stepping back, this is the most uncertain business climate in the postwar era for all industries. In our industry, many operators are hoping simply to survive. So partially, survival is not a question. Our relative advantages will shine brighter in this trying time. We will endure with relevance. With that, I'll turn it over to David for more operational details.
Thanks, Matt. I want to start by providing a little more color on our voluntary proactive production curtailment strategy. Turning to Slide 7. For the month of May, we expect curtail net oil production by up to 28,000 to 30,000 barrels a day. On a gross basis, this equates to a little over 40,000 barrels a day. And as Matt mentioned earlier, this is a choice for Parsley. The table at the bottom of the page breaks down this curtailment into various segments. In aggregate, we have a very resilient low-cost production stream, which provides us a lot of flexibility as we manage our base production. To that point, roughly 90% of our operated volumes have variable lifting costs under $3 per barrel of oil equivalent. We expect these curtailments in May to modestly enhance our free cash flow profile in 2020. Furthermore, targeted curtailments will be used as a temporary bridge to one of our key corporate ESG initiatives for this year, reducing natural gas flaring. Our operations team notched some nice flaring mitigation wins from new infrastructure solutions put in place during the first quarter, specifically on a recently acquired Jagged Peak properties where historical flaring had been high. Then in mid-April, Parsley voluntarily shut-in several pads that were flaring natural gas. This is a common sense approach in the interim. Our operations team has already lined out more permanent flaring solutions for these pads, which are expected to be completed in the coming weeks and months.
Finally, there seem to be two common questions with regards to curtailments that I wanted to touch on briefly. First, is how can -- how quickly can curtail production be restored or ramp back to previous levels? For Parsley, the answer is fairly quickly. We would estimate 1 to 2 weeks. Importantly, our marketing arrangements continue to provide us with advantaged flow assurance. So we do not currently see that as a limiting factor in restoring volumes either. To reiterate, though, the plans laid out here for the month of May, we will continue to evaluate this voluntary curtailment level on a regular basis going forward and we'll adjust production levels quickly and responsibly as the market conditions evolve.
The second common question that focuses on the impact production curtailments have on the reservoir itself. As the Permian shifted more into development mode, temporary shut-ins became part of normal operation. Based on our historical data, we have not seen evidence to suggest that temporary curtailments negatively impact longer-term reservoir integrity.
Turning to Slide 8. Our drilling and completions team continue to raise the bar, setting new company records for footage per day in both the Midland and Delaware basins. These continued operational efficiency gains helped drive our well costs even lower during the first quarter, shaving about 10% off our initially budgeted costs. And the fact that Jagged Peak was integrated during the same time frame only makes this operational excellence more impressive. When we first announced the acquisition of Jagged Peak last October, we highlighted that capital efficiency gains on these assets were going to be expected in 2020. A seamless integration effort, coupled with record efficiency enhancements I mentioned earlier, enabled us to significantly outpace our original improvement expectations. This is a true testament to the cohesive integration delivered by the Parsley team.
As market dynamics shifted throughout March, our supply chain management team led an outreach program, targeting all suppliers across all spend categories. These comprehensive efforts helped to generate line of sight to the second leg down in estimated well costs depicted in the bottom right graph. Importantly, these price reductions did not require significant supplier turnover or new activity commitments from Parsley.
In other words, these are low-risk savings we expect to generate once it makes financial sense to restart activity.
Moving on to Slide 9. In a lower commodity price environment, the advantages of being a low-cost operator are more pronounced. We have long been best-in-class when it comes to lease operating expenses, as you can see in the graph on the left. We expect this differentiated effort will continue. Recent efforts by Parsley supply chain management team helps secure price reductions on key LOE spend items. The shut-in of vertical well takes higher unit cost production out of the system, and the company's integrated water handling system is a strategic margin enhancer. Overall, this combination of factors should help offset a decrease in near-term production volumes. We're also extracting cash cost in the model on the G&A side, again, controlling what we can control in protecting our margins. The Jagged Peak synergy capture is ahead of schedule, and executive leadership was early to step to the plate with voluntary compensation reductions.
We'll continue to attack other overhead from multiple angles. In total, between G&A and LOE, we see combined cash cost savings of roughly $65 million versus the midpoint for our initial budget ranges.
And now I'll pass it over to Stephanie to review our marketing position.
Thanks, David. Flipping to Slide 10, we have long stated that our marketing strategy centers on two guiding principles: dependability and diversification. Those principles have never been more important. Our sales contracts provide us exposure to the Magellan East Houston, Brent and Midland benchmarks, and a broad portfolio of physical pipes, mitigating risk associated with a localized hub, pipeline, or port. Our counterparties on these firm transportation agreements are a collection of large international marketers with the best skill set to place barrels downstream in a challenging market. As barrels continue to flow on pipe, finding ways to market, it is safe to assume that Parsley barrels will be among those transported if we so choose, which leads me to another key advantage of our marketing position, flexibility. Although we have advantaged flow assurance, we do not have burdensome associated take-or-pay liability. First off, we will not incur any firm takeaway-related deficiency payments due to our voluntary choice to curtail May production volume. And as you can see on the table, on the left side of the page, as we pursue the stabilized activity plan for the rest of the year, our estimated deficiency payment in 2020 is only around $2 million. In other words, future upstream capital allocation decisions will not be motivated by midstream considerations. The tail will not wag the dog.
Finally, as you can see in the map on the right, our acreage fits in that API gravity sweet spot, our weighted average barrel of production is 41 degrees. This matters more than ever in an environment where refiners are shedding higher gravity crude to minimize gasoline yields and Asian export economics are challenged. Our sales volumes are not subject to any discounts applied to higher API gravity crudes like West Texas Light, which began in the month of May, trading at a $5 per barrel discount to WTI, Midland. In an environment where every extra dollar of margin will have a meaningful impact on free cash flow, possessing a favorable crude quality continues to be a nice inherent advantage.
And now I'll pass it over to Ryan to discuss Parsley's sound financial position.
Thanks, Stephanie. Now on to Slide 11. A consistent hedging program has always been a cornerstone of Parsley's financial strategy, and the importance of these risk mitigation efforts was highlighted during the recent sharp fall in oil prices. Parsley believe that increased uncertainty in crude market fundamentals required additional actions on our part to manage that risk. So during March and April, Parsley proactively managed its hedge position. We restructured our existing 2020 hedge positions to provide additional protection against lower oil prices using swaps and two-way collars. Over 80% of our hedges in the second quarter are swaps or two-way collars with unlimited downside protection.
Additionally, Parsley moved aggressively to protect its 2021 cash flow by adding swap positions, which are well in the money based on today's strip. Our full hedge position can be found in the supplementary slides.
Turning to Slide 12. Our leverage profile remains healthy, and our liquidity position was recently enhanced during our April bank redetermination. Our borrowing base was reaffirmed at $2.7 billion. Our commitment amount was increased by 7.5% to $1.075 billion, and our maturity date was extended by 2 years. These proactive steps in this challenging environment speaks to the credit quality of Parsley and highlights strong support from our bank group.
With a healthy free cash flow target in 2020, we will continue to prioritize paying down debt, returning capital to shareholders through our dividend program, and further fortifying our financial position. Turning to Slide 13. We are now budgeting at $20 to $30 oil for the remainder of 2020. In this context, our corresponding capital budget will be less than $700 million, with more than half of that spending having already occurred in Q1 '20.
Given recent market volatility and ongoing uncertainty, the company has temporarily suspended its detailed guidance on production, activity, and unit costs. But we have not altered our guiding principles, preserving stable free cash flow, maintaining a healthy leverage profile, allocating incremental capital based on unhedged economics, these will continue to serve as guideposts. To wrap things up, we are staying flexible, and we'll continue to do what is necessary to preserve long-term shareholder value. With that, we'd be happy to take your questions.
[Operator Instructions]. Our first question is from Scott Hanold from RBC Capital Markets.
I appreciate all the detail. And specifically, with the progression of shut-ins or at least defining, how you're going about that? Obviously, the bulk of it's in the bucket of POP deferrals, volume management, and shut-ins. Can you just give a sense of when you look at volume management and shut-ins, how big of that total is that? And how do you go about selecting which wells those are?
Yes, Scott, it's a chunk of it, for sure. We look at cash margin as kind of the first cut. And beyond that, there are several other variables that we look at before shutting a well and everything from its vintage, where it is, it's artificial lift type. So as you progress through this, it makes up a pretty good piece of that. But the POPs, there's about 15 POPs that haven't come online yet. So that obviously is a material piece throughout the year.
Okay. Understood. And with respect to getting in the back half of the year, if you get to your baseline view of more -- it looks like maintenance activity by the time you get into late 3Q into 4Q. How do you plan and how do you view kind of the go-forward plan at this point? Like what price do you guys feel comfortable moving above that 4 to 5 rigs and 1 to 2 frac crews as you kind of migrate into 2021? And just talk about like what kind of levels of free cash flow do you need to see? And how does that plan look moving forward?
Scott, we're going to have to take a look at the whole macro environment. We're going to be watching reactivation of these economies. We're going to be watching storage levels and inventory levels across the globe. And of course, you then have your price signal in your shape of the curve. So in a flat curve, where we're getting that $25 to $30, we're perfectly comfortable in this 4 to 5 rigs stabilized program. The returns justify the inventory set can definitely handle that for over a decade, even at those low prices.
And it generates pretty robust cash flow. So we're -- it gives us plenty of cushion as well to continue to return, return a healthy amount of cash flow to shareholders. So on the top side of that, we'll just be looking at all those macro conditions for some moderated growth to return.
And our next question is from John Freeman from Raymond James.
First question, if the stabilized activity scenario plays out for you all? And when we look at sort of the preliminary 4Q '20 maintenance CapEx number you gave for to hold that level flat into '21. What level of DUCs does that assume at the end of 2020?
At the end of 2020, we have about 40 DUCs. So that sets up for 2022, where you're able to continue to have that that lever if you need -- if you see a price signal that you like and want to accelerate a little bit, it gives you a little bit of an accelerated pedal there, also allows us to continue to deliver larger projects if warranted. So that's a DUC balance that we think makes pretty good sense to carry through 2020 and into 2021.
Great. And then just my follow-up question, sort of on the lines of what Scott was asking about. If I think about the vertical wells that have been shut-in and even the older horizontal wells, I guess sort of what scenario or price environment would you need to what -- to bring those back online? Because I assume, while it's a very small percent of your production, it's a much more meaningful percentage of the total LOE.
Well, yes, that's almost -- a significant amount of that is already cash positive. So I think right now, we'd like to see a little bit more stability. We look at storage. We look at the shape of the forward curve. So it's not necessarily about just making a positive cash margin. It's about dealing like things are balanced enough to warrant bringing those volumes back online. We'll watch. Again, inventories -- we'll watch for a little bit less volatility between supply and demand and really getting some firmer views of near-term and longer-term pricing before we commit to opening those backup.
And our next question is from Jeanine Wai from Barclays.
My first question is on the 2020 plan. So with the new CapEx reset for the year and you estimated $300 million of free cash flow at a pretty low $20 to $30. Can you talk about how you settle specifically on this plan? Meaning, are you focused on a certain free cash flow level or was it more related to maybe like a hurdle target you had on new activity and the free cash flows what fell out of that?
It was a combination, Jeanine. We came into the year with a $250 million target. And as we saw -- free cash flow. And of course, we saw drastically increased volatility. So we needed to up that cushion and still deliver a stabilized case. But then the sanctioning of projects is all driven by rate of return economics. So we still have a healthy amount of those. So then it falls back into our view on volatility here in the short term and growing that free cash flow cushion. So we definitely wanted to push on the model and make sure we could insulate ourselves in a time of high volatility.
Okay. Great. And then maybe fast-forwarding to 2021 base declines. Do you have an estimate on what your 2021 base decline looks like now given that you significantly reduce CapEx this year? I think your prior 4Q-to-4Q base decline for this year was about 40%. So curious what kind of improvement you're anticipating for next year?
Yes, that's right. It was around 40%. It drops down into the low 30s, 32%, 33% under this scenario, which has follow-on effects for years to come. So this is a quick look at 2020 maintenance cap, the $550 million to $650 million range, and that range holds true for 2022, even as you work through the DUCs because of that moderating decline. So of course, then we'll continue to work our cost and efficiencies down, but to really, really healthy and resilient go forward plan.
And our next question is from Brian Singer from Goldman Sachs.
I wanted to follow up on -- really more of a philosophical question. You highlighted a few times here that your drilling is based on unhedged rate of return. Philosophically, when oil prices are higher and potentially if oil prices in 2021 were to exceed the prices at which you hedged, would you ramp up based on hedged rate of return? A follow-up on Jeanine's question, is there a minimum free cash flow target or line in the sand when you think about next year?
It's a good question and one we hope to be addressing in the next -- in the coming months. And there will be a cap to activity. So I think we'd want to deliver a moderate amount of growth in the single digits, and that would probably cap and give us comfort. We've seen so many compounding benefits of slowing down the model, working on our efficiencies, and building a cash cushion. We are very comfortable with our leverage profile coming into this. But in a reactivated case, in the one, you mentioned moderate growth and then additional free cash pays down the debt and, of course, you're insulating the return to shareholders all along the way. So I think there would be a cap to the amount of activity we'd reactivate to.
Great. And then my follow-up is with regards to the stabilized activity plan, a couple of questions on both the productivity and the cost side. What are your expectations for well productivity and relative to the initial budget as you shift more towards the western portions in the Midland Basin? And then in the cost reductions that you've highlighted on Slide 8, do you view the stabilized activity cost improvement piece as cyclical or secular, i.e. if prices recover, do those costs go back to $900 from $700?
Brian, as far as the well performance, I mean, certainly, as you pivot more capital towards the Western Midland, in particular, I would certainly expect to see your average well increase. Hesitate to give too much specific on that yet. We're -- things are pretty dynamic, but certainly upward. And as far as whether you'd go back towards the $900, how sticky those prices are going to be from a service cost standpoint?
I think it's going to be a function of price. I think it's going to be a function of how well capitalized the industry is at that time that prices start to improve. So what is the competition level for those services if there's enough moving parts now to where I think it's probably a little difficult to project exactly what that is with certainty, but we feel like that -- on Slide 8, that middle bucket, that's something that's organic that we can repeat. And when you look at the $900 and the $700 for the Delaware and the Midland, respectively, you're probably looking somewhere between those two, even if prices were to come back up and you started to see some restoration of service costs. But we feel like the one in the middle is absolutely defensible under most realistic conditions going forward.
Our next question is from Charles Meade from Johnson Rice.
I wanted to ask a question about June. And everything is looking better today, and I echo your sentiment that that it'd be nice to go back to having to answer questions about what we do in the rebound scenario. But specifically to June, when will your volume picture come into better focus in for June? And how do you foresee the pieces coming together to see if your shut-ins extend to June or perhaps increase or decrease?
Charles, we have a lot of flexibility on when we make those calls. It will be at a minimum mid-month, 14th through the 21st, and then past that we have -- we can make the calls really on a week-by-week basis as we see signal responses. So we'll be, again, watching market conditions. And as I mentioned in the prepared remarks at a maximum, you'd see a repeat of the May shut-ins. But with things firming up, you can easily get back to that that dark blue wedge pretty quickly, 1 week time -- 1-2 week time of ramp-up of the wells.
Got it. Thanks for that clarification, Matt. And then my second or follow-up question, I think, this maybe goes back to a point that David made earlier referencing the DUCs is maybe an accelerator pedal. Specific to how you're going to make the decision to start ramping back up your completion activity, hopefully, in the back half of '20 here? Is that going to be -- are you going to be evaluating those IRRs just on the point forward completion dollars? Or are you also going to be rolling into that the drilling cost to effectively replace that DUC in your inventory?
Yes. I mean we're looking at the full side of the cost equation there. I mean, certainly, the IRRs, if you look at it from a point forward basis, will be higher, but these were wells that were drilled in high-quality areas. And anything certainly that the drill bit touches the ground on going forward is full kind of fully-loaded costs. But yes, we're not going to be making cost for decisions on any new investments. It's -- these are going to be -- these are quality DUCs that are in the ground. So we'll make rate of return prioritized decisions on all those future investments.
And our next question is from Michael Hall from Heikkinen Energy Advisors.
Congrats on navigating what has been a very volatile environment thus far. I guess I wanted to think a little bit about the restart of volumes and activity. Just get a little better feel for how you guys are thinking about that. Is it literally going to be kind of step-by-step, step-wise where curtailed volumes come back and then we bring on the wells that have yet to pop or tilt that are pop or completed rather and then start completing? Or does that all kind of start to happen all at once, once you get the price signal? Just trying to think about how gradual that is versus how quickly you bring things back?
It's driven, Michael, by the price signal and the macro view. So I mean you can have a one-day price, but then you also have the shape of the curve. But let's say, both of those firm up in unison, it would be a 1 week, all of the above. If you see -- if not, if you're seeing varying degrees of signals, you can obviously turn on your volumes that are being moderated on the production basis, you can easily pop the wells that are drilled out and then you can reactivate the lower margin wells. So it just depends on the magnitude of both the price signal and the macro conditions. But the quickest you could reactivate is about a week. And then after that, it would take -- it would be stepwise throughout all the matrix of the wells that are shut-in.
Okay. Yes, that's helpful. Just trying to get a handle on how you're thinking about it. That's helpful for sure. And then I guess as it relates to signals, are you seeing any anecdotes in the field currently that suggest the physical market has improved? Where we stand today relative to what it looked like at the height of the downside volatility that came with last month? Or any insights or anecdotes you can provide on that front?
Sure, Michael. This is Stephanie. As Matt and David both mentioned, just really watching the macro. We're watching May and June. We think Midland may be short volumes in June, and that's providing the uplift that we're seeing recently -- or sorry, in May that we're seeing recently. For June, I think it's a few different signals. We -- with all of the curtailments across the space, I think there's no concern about volumes flowing. We don't have concern about being able to place those barrels. And I think the price of the volume or of the crude is essentially showing that. We continue to watch the June role and the desk, and those will close out around the 20th and 25th of May and will give us additional price signals and help determine what we plan to do in June.
Our next question is from Brian Downey from Citigroup.
Just wanted to follow up on Brian's earlier question. I'm curious what explicit well cost or service pricing level assumptions are baked into the maintenance scenarios that you show in Slide 6 into next year?
Yes. We have -- basically what we show on Slide 8, those types of costs per foot are what's baked into our end of 2020. But going forward in 2021, we're not assuming that we -- in all cases, get below those numbers. I think we're going to have to see how the industry responds, how much activity returns to the basin before we really know. But the range that we put out there for that capital, for the maintenance CapEx, should encapsulate those potential outcomes.
Okay. And then the 4 to 5 MBo/d that you mentioned are shut-in in the Delaware Basin due to gas flaring. Could you just remind us the process to reduce that flaring and return to production once pricing cooperates? Is that something that requires any further capital? I'm just trying to dimension how timing there may be oil price dependent versus other factors?
Sure, Brian. This is Stephanie. As we reported last quarter, a decrease from that original about 20% on the legacy Jagged Peak volumes that were flaring. We had line of sight for further mitigation throughout 2020. And we're actually able to -- we were able to hit our year-end goal of less than 5% on these assets. Those efforts included both internal mitigation efforts and successful implementation of additional gas gathering infrastructure by our midstream partners. The pipe that we referenced last quarter, that was going into the ground, that's actually being tied in as we speak and will be in service this week, targets our main gas gatherer on those assets, and they will also be adding additional compression and sour gas gathering to essentially fully mitigate that additional 4,500 BO that was associated with those flared volumes. So at this point, no additional capital needs on our front. And overall, just successful execution across the board for both Parsley and our midstream partners.
Our next question is from Leo Mariani from KeyBanc.
Just wanted to ask you a question on the dividend here. It was certainly nice to see you guys come out and kind of reaffirm the dividend here this quarter. Just given the strong levels of hedging this year and the expectations for free cash flow this year and next, do you guys feel pretty good about the dividend here in terms of being able to kind of maintain it pretty solidly throughout this enormous trough in the energy cycle?
Yes. Leo, we really do, and it's a priority for us. You can see on this projection, it's about 27% of free cash flow goes back to shareholders, and then we have extremely well-hedged position going into 2021. So we're going to continue to make that a priority. It's been a long journey to get here. We didn't take the decision to start a dividend lightly. We wanted to have the right amount of cushion, and we do feel good about the quarterly analysis that the Board will do, and we think that there's plenty of cushion and it's a priority for us.
Okay. That's helpful. And I guess just in terms of activity levels, I mean it sounded like you guys had kind of really shut everything down, sort of, mid-April. Just trying to get a sense -- I know it's kind of quite tricky here, but it sounds like maybe there's some kind of lingering spend kind of into April here. And then, obviously, you guys are kind of reevaluating when to kind of start things back up, just depending on how it plays out. But I guess just kind of in the downside scenario case versus, I guess, the no spend for the rest of the year versus the upside at $700 million here, just trying to get a sense of kind of spending trajectory. Is it fair to say, in the upside case, the restart kind of starts sort of circa June 30 and the CapEx starts picking up in the second half and accelerates into 4Q? And you can tell us qualitatively about the stabilization case?
I mean I think you just did a pretty good job of describing what that stabilized activity would look like. Yes, probably near the beginning of third quarter, restart and feathered-in, not necessarily a slam the throttle case, we'd be able to kind of ease into it, but maybe a little more capital in the fourth quarter. The first part, if you were asking if we -- I've kind of got the impression you're asking if there was a bunch of lingering spend, where would spending be if we -- if you went with that dark blue case on the production volumes? And I wouldn't say there's much lingering spend. I mean there's a pretty healthy ramp down pace that we underwent. So I wouldn't look at a lot of lingering and follow-on on spend. We have a high degree of confidence that we'll be under that $700 million ceiling in all cases.
And our next question is from Neal Dingmann from SunTrust.
My first question really Matt, or the team pertains to Slide 6 and really your forward production. It appears looking at Slide 6 that the activity returned at the beginning of the third quarter, that no question, your production will be more than stable in '21. I'm just wondering if this didn't occur, and you continued with limited or no drilling and completion as well as some shut-ins, could you just address kind of your thoughts on trajectory into '21?
Yes. The limited activity would pretty much follow that PDP shape. And of course, as David mentioned, we have 15-or-so wells that are waiting on the banks ready to get on the field. So we feel comfortable about that smooth trajectory there. And then as we reengage and feather-in, in the third quarter, you don't see an immediate response. It takes a few months for those new capital projects to get in line, which is why you still see natural decline before you run into the stabilization model.
Okay. Okay. Very good. It makes sense. And then my second question, really, Matt, just on -- I think you hit this a little bit earlier, but just a little on activity and hedges. I'm just wondering, you mentioned you wouldn't drill through your hedge book, which makes sense. But with that $20 to $30 scenario that you all are laying out, I mean do you all sort of look at your activity and hedges somewhat exclusively. Or as today's and other ways, is it purely just these unhedged well economics that you look at and not necessarily your hedge levels?
Yes. Yes, that's correct. We want our capital projects to generate returns on their own. We view the hedges more as support for the balance sheet as opposed to support for the capital program.
And our next question is from Josh Silverstein from Wolfe Research.
Matt, just targeting a couple of things on the growth rates you were talking about previously. Has the idea of 10% growth been kind of thrown off the table at least for the foreseeable future? This was something that you guys were previously targeting around 50 WTI. I was just wondering if given all the lower costs right now if that has actually been moved lower for you guys to be able to grow that amount?
That's a great question. We'll have to evaluate it when we get to that point. The inventory set, the balance sheet, everything could deliver it. But I think when you see negative pricing printed on the books, you have to change just as an insurance actuary would change how they would gauge risk. We have to change that. And just as our free cash flow target this year went from $250 million up to $300 million to give us additional cushion, I think that's going to be pretty enduring for the long run. So we haven't reassessed the $50 case, but our bias would probably be more in the high single digits.
Okay. Thanks for that. And then you made some comments before about how increased spending could happen. Does the revolver need to be down at 0 before thinking about increased spending? And does increased growth spending occur at the same time as an increased rate of return profile or capital return profile?
We're constantly looking at the shape of our leverage. And of course, the revolver goes into that. But that gets paid down nicely kind of by coincidence in this shape. So that wasn't the trigger the revolver specifically. But yes, you want to see lowering leverage and continued free cash flow growth. So yes, that goes in -- into the mix. We want to stabilize leverage and decline it over time.
And our next question is from Asit Sen from Bank of America.
On the potential restart, you mentioned on a quick 1 to 2 weeks. My question is more on efficiency. In the past, Parsley has gone in great lens to improve operational efficiencies. So as you put production back, how easy would it be to recapture some of those efficiencies once the market returns? And in a low price environment, looking into 2021, would your development plan change in a low price environment, whether on pad size or well spacing? Any thoughts on that.
As far as the efficiencies are concerning us, I mean that is a major goal for Parsley going forward. We just printed a record D&C efficiency quarter in the first quarter. So we are very focused on making sure that we head out of the starting blocks at full speed, and that's not going to be easy, but the entire organization is preparing for when that happens, let's make sure we get out of the way at or out of our own way and get that done effectively. So capturing the elements of what enabled us to accomplish what we did in the first quarter, being very intentional about working with our suppliers, and getting ready for that when it does happen. It's a huge focus because we don't want to lose momentum there. And as far as bringing wells back online, that's something that we've done before, not at this scale, of course, but we think that we can do that with efficiency, both in terms of speed of bringing volume back on as needed and then in terms of cost as well.
And our next question is from Jeff Grampp from Northland Capital Markets.
Just sticking on the topic of free cash flow. As we look out into 2021 and see that trend continuing and maybe even expanding, just kind of curious to get your all thoughts if you could kind of maybe fore shrink the opportunity set within uses of that free cash flow, whether that would be potential dividend increases, buybacks, acquisitions, things of that nature?
I feel comfortable with our dividend level, and we want to make sure it's a priority and sustainable in multiple outcomes. So I think, 2021, the priority is going to be on debt pay downs.
And our next question is from Gail Nicholson from Stephens.
A quick question on LOE. 90% of the operated volumes have variable lifting costs sub $3 per Boe. Can you talk about the components that make up that $3 per Boe on the variable lifting cost?
Sure, Gail. I'll speak at a high level. I mean there are certain things that that are variable probably regardless of which operators you'd ask, chemicals, water disposal, come to mind, things like electricity. So I would say we're probably similar in how we characterize that to many operators, more of those true per barrel costs on the LOE side. And we say that 90% of it is below $3 per Boe. And most of those barrels are well below that. So it just speaks to the ability of these wells to capture strong positive margins even these suppressed commodity price environments.
And our next question is from Phillips Johnston from Capital One.
My question relates to Slide 6. I appreciate the chart that shows oil production might look like throughout the rest of the year. My question is, what do you think your oil mix might look like over that time frame? I guess there's 2 factors there. First, you're flaring less gas going forward? And second, your producing wells will presumably see higher GORs as they naturally roll down the PDP curve and, obviously, the run rate of new well POPs to sort of offset that trend will step down significantly?
Yes. I'd say we're -- we predict 63%, bringing back online with some infrastructure here, some gas, so maybe 61% to 62%, and that should capture any natural GOR increases over time. That's kind of our historic run rate as we flatten activities here for this year.
And then our next question is from Gabe Daoud from Cowen.
Just a quick clarification for me. Is the $600 million maintenance capital number, an all-in number or is that just D&C?
Yes, Gabe, that is definitively an all-in number.
And we have reached the end of our question-and-answer session. And with that, this concludes today's conference, and you may disconnect your lines at this time. Thank you for your participation.