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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Welcome to the Pioneer Natural Resources First Quarter Conference Call. Joining us today will be Scott Sheffield, President and Chief Executive Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; Joey Hall, Executive Vice President of Permian Operations; and Neal Shah, Vice President, Investor Relations.
Pioneer has prepared PowerPoint slides to the supplement their comments today. These slides can be accessed over the Internet at www.pxd.com. Again, the Internet site to access the slides related to today's call is www.pxd.com. At the website, select investors, then select earnings and webcast.
This call is being recorded. A replay of the call will be archived on the Internet through June 5, 2020. The company's comments today will include forward-looking statements made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995.
These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements.
These risks and uncertainties are described in Pioneer's news release on Page 2 of the slide presentation and in Pioneer's public filings made with the Securities and Exchange Commission.
At this time, for opening remarks, I would like to turn the call over to Pioneer's Vice President, Investor Relations, Neal Shah. Please go ahead, sir.
Thank you, Margaret. Good morning, everyone, and thank you for joining us. Let me briefly review the agenda for today's call. Scott will be up first. He will have some opening remarks in this unprecedented environment. He will also discuss our strong first quarter results driven by solid execution from the teams and our continued efficiency gains.
After Scott concludes his remarks, Rich will then update you on our strong financial position and balance sheet strength while delivering best-in-class oil production. Scott will then return to discuss Pioneer's focus on sustainable practices and our commitment to social and governance issues.
After that, we will open up the call for your questions. Thank you. So with that, I'll turn it over to Scott.
Thank you, Neal. Good morning. I appreciate everyone taking the time to listen to our call this morning, and hope you and your families are safe and well. I think it's important to begin by thanking the health care workers, first responders and all people on their front lines the coronavirus.
I'd also like to thank all of our employees at Pioneer for their hard work and dedication during these challenging times. Pioneer entered this unique time and position of strength, supported by our pristine balance sheet and our strong derivatives position.
We have adjusted our 2020 plan to the current environment, reducing our CapEx by 55% at the midpoint, yet maintaining similar production levels for the year 2019, demonstrating a highly capital-efficient program that continues to get better. Just as Pioneer entered this downturn is one of the best positioned companies, we will emerge just as strong.
Turn to Slide 3, and you see we're taking action to protect our employees and also lower our cost. Going to Slide 3. The key points here, obviously, is maintaining our top-tier balance sheet through capital discipline, combined with significant cost reductions in 2020.
We're lowering our CapEx by about $300 million from the March update. What's more important on production expenses is a program we started about a year ago after our returns, we decreased $60 million to $70 million on an annual basis in our production expenses. A lot of it has to do with our vertical program. A year ago, our vertical operating expense was about $35 per BOE. We've lowered it all the way down to about $20 per BOE.
You'll see later on a later slide, our horizontal operating cost is down to about $2.50 per BOE. In addition, we're taking about $80 million to $90 million of corporate overhead related costs. If you remember last year, we took about a little over $100 million all. Both myself, the officers and the Board of Directors are taking voluntary reductions in compensation. You look at myself, it's over 70% of cash compensation reduced from last year. We're also suspending annual cash bonuses for employees and implementing additional cash G&A reductions.
Again, we were top quartile last year, will continue to be top quartile. Our capital allocation priorities are balance sheet, dividend and capital spending. Going to Slide 4. We are at the upper end of guidance on both on production; also significant capital efficiencies, which Joey will talk about in a minute; and further cost improvements. We're generating about $100 million of free cash flow in the first quarter.
Going to Slide 5. Again, a key measure going forward is how low can we get these costs. When you look at just cash cost on horizontal, it's 2 50 of BOE, G&A cash cost down to about $1.50 and interest $0.8 for a total of under $5 or $4.8. Again, with the high net revenue interest combined with these low cash costs, continue to improve cash margins when we compare it to peers.
When you take both LOE and G&A savings and what's important is the fact that we've already achieved this in the first quarter. Some of our peers are just forecasting they're going to achieve it. We've achieved it in the first quarter. Annual savings of $140 million to $160 million a year.
Go to Slide 6, our updated operational plan. Again, the key point, capital down 55%, while maintaining flat production from 2019 levels. Our fourth quarter exit estimated to be about 190,000 to 195,000 barrels of oil per day. Average rig count for the -- during the next 3 quarters be 5 to 8 on rigs with 1 in the joint venture area, frac fleets averaging about 2 to 3. We're continuing to see significant reduction in well costs, which Joey will talk about in a minute.
In addition, in regard to deferrals, we have about 7,000 barrels of oil per day currently curtailed. That's primarily high operating cost vertical wells. Our precise activity letters -- levels will be a function of the macro and oil price outlook. And obviously, we don't anticipate it, but potential future curtailments. Again, reminding everybody stable production year-over-year while reducing capital by 55%.
Going to Slide 7. Again, we have an unmatched footprint, world-class asset in the Midland Basin. Average acreage cost is about $500 per acre compared to the peers of about $34,000 per acre. We still have over 10 billion barrels of oil equivalent resource base, 680,000 acres. This all comes to enhancing corporate returns in ROCE as we go forward. Slide 8. Again, comparing the Delaware, the Midland, a couple of key points here. The pricing in the Delaware is getting more expensive for oil, as indicated on the graph.
Also a note, many of our peers that have both Midland and Delaware have reallocated a higher portion of their drilling activity to the Midland Basin from the Delaware. In addition, when you see our flaring slides later on in the presentation, obviously, the biggest culprit is in the Texas portion of the Delaware. It's about half of the flaring activity in the Delaware due to lack of infrastructure.
I'll now turn it over Rich.
Thanks, Scott. I'm going to start on Slide 9, and good morning to everybody. This slide really speaks to the relative net debt-to-EBITDA levels that our peers have as forecasted by Credit Suisse at the year-end 2020. And as you can see, we have one of the strongest balance sheets in the peer group, as evidenced by our low leverage ratios in the slide depicted.
I think it's precisely for these times that it's important to have a strong balance sheet. And I think this slide emphasizes the importance of it when you look at the levels of where some of the peers could be from a net debt to EBITDA at the end of the year. I think it's also important that when you look at the actions that Scott outlined that we're taking in 2020 to reduce our capital program by $1.8 billion or 55%. And then also the other cost reduction initiatives really will ensure that we exit 2020 with a similarly strong balance sheet.
Turning to Slide 10 where we look at our derivative position. There, you can see that our derivative position and what those settlement values are at various prices for the rest of this year and Q2 to Q4. You can see that it provides significant cash flow support in 2020, further protecting our balance sheet. Similarly, we have added positions for 2021. We have 135,000 barrels of oil a day at production protected at $43 Brent with upside for 2021.
Just to be on the safe side, we did increase our liquidity position early April by adding a 364-day credit facility, a little over $900 million that get our liquidity up to $2.4 billion. I think when you look at what Scott said being best positioned to emerge from the downturn and what we've done on the balance sheet, you can see that our rating were reaffirmed by the credit agencies here recently. So definitely, well, protected on a strong balance sheet.
Turning to Slide 11 and really talking about the long-term benefits of firm transportation. I think it's important that you take a long-term views of our FT, and we believe moving our barrels to the Gulf Coast and getting access to the world market will provide incrementally better pricing. I think that's evidenced in 2018 and 2019 when we had over $700 million of incremental cash flow from -- by moving our barrels to the Gulf Coast. Clearly, the market disruption in the first quarter and to a lesser extent here in the second quarter impacted us, and we are experiencing some short-term declines in commodity prices, and that is mainly related -- and will impact that's mainly related because our barrels that were in transit and as prices reverse and stabilize, we'll begin to recover that money back in future months.
But in addition to the ability to move our barrels to the Gulf Coast and access world markets and improve margins, it also minimizes our exposure to the Midland market and any purchaser curtailment. It's really that we're moving all of our barrels out of the basin, so we should not be subject to curtailment. Anecdotally, I can tell you that we've sold all of our April and May volumes on the Gulf Coast, and we're well on our way on June sales.
After talking to our marketing team, I can tell you that things feel much better than they did in May and June market feels stronger and more positive than we did in May.
So things are on the right track. So with that, I'll turn it to Joey.
All right. Thanks, Rich, and good morning to everybody. I'm going to be starting on Slide 12. And I want to start off by congratulating and thanking the entire Pioneer team for an outstanding quarter, especially during these challenging circumstances. You haven't just kept things steady, you've taken it to new levels.
Reflecting back on 2019, it was undoubtedly one of our best years in terms of safety performance, efficiency gains and cost reductions with that momentum has carried strongly into 2020. When you look at the graphs on the left, it's important to point out that the dash lines represent the efficiency gains we expected to achieve for the full year of 2020. But as you can see, we have already exceeded these full year targets in just the first quarter. These efficiency gains, coupled with service cost deflation, are continuing to drive down our well costs.
Our production operations team is doing what they do best by intensely focusing on lowering our LOE. We're also limiting our maintenance activities and curtailing our higher cost vertical well production, as Scott mentioned earlier. We believe that approximately 75% of our operating cost reductions are sustainable going forward. Lastly, it's also worth noting that due to our Midland Basin acreage position and deep inventory, our development strategy is unchanged and remains focused on well returns.
I'll now move to Slide 13. Starting on the left, once you normalize gross production for all peers on a two string basis, Pioneer has the highest oil percentage. And then moving to the right, we also have the best 24-month cumulative oil production. Summing it up, Pioneer has the production mix and drills the most productive wells in the basin. These two facts combined should lead to the best margins and the highest returns compared to our Permian Basin peers regardless of oil price.
Once again, I want to express my congratulations to everybody on a great quarter, and I'm going to turn it back over to Scott.
Thank you, Joey. Slide -- a couple more -- 2 or 3 more slides. Slide 14. Again, this is a slide which we showed last quarter. Shell is still very important resource. And it's providing one of the -- the second lowest in regard to emission barrels in regard to oil around the world. Going to Slide 15. This is an update from Rystad updates, there are numbers about every quarter. What's positive here, a couple of things.
Pioneer still is the lowest intensity in regard to everybody in the Permian basin of all operators. In regard to flaring intensity, as indicated in the light turquoise color versus the darker blue color, you can see improvements. Also another note is that 75% of the companies are improving. So congratulation to right for putting out this data. I think peer pressure does help, as indicated here, as companies are continuing to improve.
Lastly, another way, obviously, to prorate. I mentioned this at the hearing. Whether or not the Railroad Commission will act, I recommended that they shut in all companies that are above 2% in regard to intensity, in regard to flaring intensity. So I don't expect them to do something, but hopefully, over time, they'll get stricter and stricter. Going to Slide 16. Again, the key point here. All these come together in regards of driving value for our shareholder base.
So I will stop there and now open it up for Q&A.
[Operator Instructions]. We can now take our first question from Brian Singer from Goldman Sachs.
Scott, if we look at the cost reductions that you're highlighting on the capital side and operating in the G&A side, what do you believe will be lapping versus temporary? You talked about some temporary reductions on D&A. I know there are other things that are going on. But can you talk to how you see Pioneer's secular cost structure versus cyclical cost structure
Yes, thanks. As Joey mentioned on the operating expense, we'll definitely achieve at least 75% or greater of those going into future years. It depends on how many of these high vertical wells will come back at a higher price in that regard, but we'll definitely achieve 75% or higher of the operating expense. In regard to the G&A, I'm estimating somewhere between 60% to 75% of those will be achieved through either different ways we do business, less activity and other reductions. It all depends on the forecast and what happens with the strip.
Using Goldman Sachs numbers, I noticed you all came out recently was $65 Brent by the end of the year. Obviously, that's a big change from end of 2021. That's make a big difference where the strip is. The Brent strip today, I think, is around $38. So it all depends on the macro and what the price outlook is, Brian. But we hope to achieve somewhere between 60% to 75% of G&A and 75% or higher of the operating expense going forward.
Great. And then my follow-up is with regards to free cash flow versus growth and then returning capital to shareholders. Have your views evolved in recent months on the balance between Pioneer growth versus free cash flow, assuming some type of oil price recovery scenario? And can you provide any update on the engagement levels that you had in recent months on variable distribution variable dividend mechanism?
Yes. It all depends on the price world we get back into, but I don't know if we'll ever get back into the 60s long term. We saw what happened. We all dependent on $60 Brent, $55 WTI for the last 3 to 4 years since the OPEC+ agreement was put in 2016. I'm going the premise that we'll be back to $45 WTI and $50 Brent at least at the minimum. Under those levels, I think there'll be very few companies growing in the shale industry.
Most of them will have to use a lot of their extra free cash flow to delever. Obviously, Pioneer will have the option whether to pick -- go back to 15 or go to 10 or go to 5. But really, that's a decision we'll make at the appropriate time. We have an asset base that can provide those opportunities. But we're definitely focused on free cash flow is going to be our main driver in determining that. So it's really hard to pick a number right now, long term.
Got it. And the variable in--
Yes, on the variable -- sorry. Yes. On the variable, I'm still a firm believer of the variable dividend, especially when you have -- we've had 3 downturns in the last 11 years in our industry, 2009, 2014, and I guess, 2016, and downturns are coming more quicker it seems like versus the first 25 years in my career. And so I think a variable dividend will play well, have a good base dividend. And so if we see a run up in price, which I hope we do at some point in time, to $65, $70, $75 Brent, we'll think that excess cash flow and distribute it to our shareholder base as a variable dividend. I think it's the best way in regard to managing this business going forward.
We can now take our next question from Scott Hanold from RBC.
Just following up on Brian's question a little bit on the longer-term plans. And just so I make sure I'm hearing you right. I know you had a sort of vision of mid-teens growth and adding 2 to 3 years per year. Obviously, a lot changed. I understand that. But fundamentally, as you look forward to that long-range plan, given what's happened in the last several months, are you kind of shifting your perspective on that longer-term growth rate?
No. My key point is, is that it's hard to tell at this point in time. If you look at the strip for the next 5 years, the strip, historically, if you go back in time, the strip in downturn is generally too conservative. The strip in an upturn is generally too optimistic. So we're probably going to be somewhere in between. And like I said, I'm probably lower my long-term scenario to an average price of $50 Brent.
So if well costs continue to drop like they have, our cost structure coming down, then we'll have choices, whether it's 5%, 10% or 15%. I just can't tell you at this point in time what to do. What generates the most free cash flow is probably going to be the program we go down.
Okay. I appreciate that. That's clear. And my follow-up question is, you certainly -- and I think you've indicated that we're a vocal supporter of production curtailment. And I guess you talked about curtailing rate around 7 a day. Can you give us a sense on where do you think your peak rates could be at and considering, obviously your vocal support of curtailments, why not take more a bigger action, right? Why not set an example and take a lot more off-line?
Yes. The whole key point of pro rating is mainly to get a cut around the world of 15 million to 20 million barrels a day. If we can rebalance storage quicker and get achieved cuts of 15 million to 20 million barrels a day, I'm talking about true cuts, everybody needs to realize these curtailments are all going to come back in the next 30, 60, 90 days. And so we were looking for what I call true cuts versus curtailments, and we were looking for a much higher price for us and for the industry. And that's the only reason that we were moving down pro ready.
What's being curtailed is the 7,000 barrels a day. Even though we're hedged and we're making decisions at those operating costs exceed certain vertical wells, and that's the only reason those wells are shut in. And most likely, they're going to come back, especially with the run-up in prices. So I hope that explains the difference between the two.
In the peak rates, where do you think you could be at peak?
Peak production rates? Or peak activity?
No, no, peak -- yes, peak curtailments, I'm sorry. So peak curtailments -- you're showing it a
Yes, we don't really -- yes, given our low-cost horizontal production, our cash costs, as Scott talked about being under $5, I really don't anticipate any more than the 7,000. Those were our high-cost vertical wells. And given what's happened to the forward strip, I wouldn't anticipate any more than that.
We can now take our next question from Doug Leggate from Bank of America.
Can you hear me okay?
Yes, Doug, how are you doing?
Good, Scott. Good to hear from you. So guys, I wonder if I could start off with your capital plan. Truly remarkable resilience that you're able to cut sending as much as you have and hold production flat. So my first question is, should we think about that then as being a sustaining capital level because it really speaks to the free cash capacity of the business, and I've got a follow-up.
Yes. If you remember last year, we had 2.1 to 2.2 billion to keep production flat. And so it's amazing what we've been able to achieve with and our drilling and completion and efficiencies, service cost reductions, operating cost reductions. Every time you go through a downturn, our industry gets better and better at docking. So I think we should be able to continue to achieve what we're showing this year going forward. So I'm very optimistic too.
Well, Scott, my follow-up is, obviously, I want to talk a little bit on -- you've been very vocal, obviously, about the Road Commission and waste of growth in excess of reasonable demand and all the other things that have gone into that. It's all very backward looking, obviously, because the industry did that, and that's the past.
But in terms of your comments around the model going forward, you've talked about historically that a 15% growth rate was optimal for Pioneer. But obviously, if the whole industry does that, we end up in this kind of oversupply situation. So can you at least -- I don't -- I mean, don't want to be drawn too much on the details, but can you frame for us what we think the U.S. industry and Pioneer specifically is thinking by way of that balance between top line growth and the potential to find return extraordinary durable share cash flow to shareholders?
Yes. Doug, like I said earlier, it all depends on the strip. The strip right now, I've been on record saying U.S. production is going to drop probably 2 million to 3 million barrels a day by the end of '21. That's at the current strip. The strip keeps moving up. And so we could be down to 10 million to 11 million barrels a day from 13 early this year by end of '21.
As cash flow increases, a lot of companies are going to use -- they can't raise equity, so they're going to use their cash flow to repair their balance sheets. And that's about 90% of the independents, the ones that are public and also private. And if you had to get me to forecast, if we're in a $50 Brent world, the growth rates will definitely slow down for both Pioneer and for the industry. There'll probably only be a handful of companies that can grow, maybe 5 in my opinion, in the $45 to $50 WTI and Brent world. It's much higher. I know for a fact what Pioneer would do, we're not going to increase the growth rate. We're going to give it back to shareholders. Some companies may take that cash and jump back into the same model that's been destroyed over the last 10 years, focused on growth.
It's hard to tell what other CEOs will do in that environment. But right now, it's really hard to predict whether we're going to grow 5, 10 or 15. But in a $50 Brent world versus $60 Brent world, I would guess our growth rate may moderate so.
I think you've got the potential to really leave a thought we go on this, Scott, as you've always been. So I really appreciate your comments.
We can now take our next question Jeanine Wai from Barclays.
My first question is on the debt maturities. In terms of the debt that's coming due next year, is the intention to pay the $500 million strictly out of free cash flow? We've seen that the debt market is selectively open and Pioneer is a very high-quality company. So would Pioneer consider tapping the debt market to extend the maturities, given that you also have $600 million coming due in 2022?
Great question, Jeanine. And I think, as we've demonstrated, we've got plenty of liquidity with over $780 million of cash on the balance sheet and a $1.6 billion of liquidity into our undrawn credit facility. So we easily pay it off out of existing liquidity, if we chose to. But I think, as you mentioned, the bond market has improved. And so I think it -- we'll have to continue to monitor the debt markets, and that is always an option that we could do as well. So it's just something we're going to continue to assess.
Okay. Sounds good. And then my follow-up question, it's kind of in regards to question. In the past, you talked about having the balance sheet to act counter cyclically, if you choose a veto, and there are benefits to doing that with and whatnot. And I know we're in the middle of rally here, but Brent is still only, what, $31. So if we see a pullback in oil prices, to what extent are you willing to lean on the balance sheet support long-term value? I'm not necessarily asked that like 515 just in terms of supporting long-term value. Is the extent of that lean, is that really tied to a self-imposed leverage target, which I think in the past has been somewhere around 1x, but that might be a little different now? Or is it more binary that you're just not going to
The reason we prepared for another downturn, we had debt-to-EBITDA go down to 0.5. And that's the reason why you need to have a great balance sheet in this industry. In fact, we've had some shareholders say we ought to get down to 0 debt before the next downturn. So -- but we will -- this is the time you lean on it. So everybody is lending on their balance sheet now, it's obvious.
What's nice is that we're starting at 0.5. So it will go a little bit higher, but not much. So -- but we will lean on it because you have to, during times like this, it's obvious. So that's why you got to start with a great balance sheet.
So yes, I think, Jeanine, also, if you just kind of look at it, when you look at our balance sheet, the debt level in the grand scheme of thing fully doesn't change that much. Really, what's changing is the EBITDA. So when you look at it from a leverage metric, so yes, it will flex up a little bit as prices are down. But as prices improve, we'll flex it back down to where we've been historically.
Okay. And so is your historical commentary about that of 1x, is that still kind of about the right range?
Well, I think, like Scott said, it can depend on commodity prices. So I could say it flex above 1x in the near term, just -- or if prices stay low for a while, but with the idea that we're going to move it back below 1x when prices improve.
Next question comes from Michael Hall from Henan Energy Advisers..
Missed some of the earlier questions, so apologies if any of this is repeated. But I'm just curious on the activity profile for 2020. The range in rig count and frac crew counts are reasonably wide, and we don't have kind of well cast to work around. How are you thinking about those ranges? Are those -- we're at early and then kind of move down to 5 by the end of the year on the rig count? Or is that a range that will be more of an average that's dependent on the price environment?
And then, I guess, also, are you guys expecting to be exiting the year with a substantial DUC inventory? And are you willing to provide an exit rate for us?
Sure, Michael. It's Neal Shah. Great questions. And I think you'll see the cadence of -- if you think about how the capital is and the 1 4 to 1 6 guidance roughly, call it, $600 million, $620 spent in the quarter. When we initially came out with guidance and the revised guidance in March, we pointed to taking the rigs down to the 11 and then roughly running 2 to 3 frac fleets, we were able to accelerate that. And we really started dropping our rigs to where we're roughly around 7 rigs right now, running 1 frac fleet. Allowing us to build up our DUCs to what I would say is a more greater than a normalized DUC count, if you look at a, let's call it, a working inventory of DUCS.
So I'd say we're running at somewhat of an elevated level. We'd expect to remain at an elevated level, exiting 2020, really providing that optionality and that flexibility to 2021 prices, should we get the economic signal to do so.
And now if you're running 1 frac fleet currently, and we're pointing to 2 to 3, that naturally says that the frac fleet count would have been increasing into Q3 and again, increasing into Q4, relatively speaking.
The rigs second through fourth quarter average is around 5 to 8. We're running 7 currently, as I said. And so you'll see that flex, as Scott and Richard said, really depending on the commodity, our outlook, the macroeconomic signals and stability and the forward strip.
In terms of exit rate production-wise, I mean, we're -- as you know, we had first quarter 223,000 barrels oil a day and really forecasting for the year to 198,000 to 208,000 barrels a day. So when you think about the midpoint of that being 2 0 3 and second quarter with the curtailments will be down from the first quarter. So it really points to second half exit rate type numbers and 190,000 barrels of oil per day to 195,000 barrels of oil per day to be in the range for the annual range of 1 9 8 to 2 0 8.
Great. That's helpful. And then, I guess, following on to that, as you think about -- it was alluded to earlier that you kind of maintain the current spending levels or sorry, the current capital level, you're optimistic that that's an achievable level going forward. I guess I'm trying to think also to the extent that there's any potential further improvements. As you said, in downturns, the industry and pioneers get stronger, typically from a cost structure standpoint, how much more room do you see on the secular efficiency gain front? And how might that theoretical benefit the maintenance capital level for -- as we think about 2021 and beyond?
Yes, Michael. So from an efficiency perspective, as you can see, what a great first quarter we have. And I've then quoted numerous times about the best thing that can happen to you from an efficiency perspective, it's slowing down. That's always helpful and it gets you intense focus on everything. We're certainly getting the benefit of service cost deflation like our rig prices are tied to WTI as are some of our other commodities like CTG and stuff like that.
So efficiency gains from my perspective are sticky and will continue. I would find it difficult to think that we could achieve what we did in 2019 and 2020. But as you can see in the first quarter, we achieved what we had hoped to for the full year. So I always never hesitate to think that we couldn't continue to see those going forward, particularly at a lower activity level and higher focus on everything that we're doing.
And Michael, from a maintenance capital perspective, you referenced that the exit rate that Rich spoke of earlier and the efficiencies that we saw in 2019, we saw here in 2020 early on, even just from the first quarter and even from what we're able to announce today. I mean, that revised capital budget of the 1 4 to 1 6 on an exit rate from 2020, roughly flat to down from the capital budget would maintain that exit rate into 2021.
Next question comes from [indiscernible].
I had a quick question on well costs. I think everyone talked about the efficiency gain. You've all continued to be able to turn in line more wells than we expected. Just wanted to think about where well costs should trend by year-end, given continued efficiencies that could occur throughout the rest of the year?
So good morning, Jamal. Looking at -- going back to whenever we put out our original 2020 budget, if you did the simple math on dividing up the POPs and the overall capital budget, we were looking at a cost of around $8.75 million per well. And based on our Q1 performance, I would say that's come down to the range of about $7.5 to $8 million.
As I talked about in the previous call, certainly, some of our cost reductions are related to concessions from our vendor community. And you could expect if activity picked back up and some of those might reverse. But giving an example like rig rates, for example, being tied to WTI, where rig rates are only 11% of the total well cost. So even if those bounce back, it's not going to have a material effect.
One of the unique things that kind of illustrates this so is that whenever you look at our efficiency gains in our cost reductions that are about equivalent, and typically, that's not the case. Usually, an efficiency gain percentage just not equal an equal percentage of cost, but we've been successful through our supply chain group and navigating through this in good times and bad times, and we've actually been able to achieve similar cost reductions as we have and percentages of efficiency gains. So I don't expect any significant reversal from a cost perspective. And on top of that, I expect efficiency gains to continue. So I'm optimistic on things going forward.
All right. And just to use you all as a barometer, given the large legacy vertical base. Should we expect for curtailment to reverse substantially as we look at an improved strip in June, July? And just on the opposite side, if we were to see prices returns, at what price do you think you'd see much higher curtailment in your vertical base?
Yes. I think when you look at it on a -- I can't speak for every other operator. I think it's probably a cash margin analysis that each of the companies are doing in terms of curtailment and what their contracts are with who their purchases are, whether they have firm contracts for month-to-month contracts that are driving that.
I think it's got enumerated in where our vertical costs have come down to, I think it will be a function of price and clearly, prices have moved positively. So at the margin, you expect to see some of those start coming back on if people want to see stability in the price. So if we see another month or so of that, you'll start to see some of that come back on. Conversely, if you saw prices go back down, like what we saw in late April, then I think you'd see potentially more volumes get shut in.
Next question comes from John Freeman from Raymond James.
I was just following up on Michael's earlier question. Could you give us what the - a rough estimate for POPs is on this new plan?
John, it's Neal. Due to the macro uncertainty and the variation of the volatility that we've seen out there and the fact that we're not providing quarterly guidance we really haven't been able to provide, I'd say, a forecast around pops. Let me maybe help from a modeling perspective though and kind of set the table in terms of capital production that might serve as a helpful guide.
If you think about capital, obviously, Q1 will be the high point in capital. I discussed how we're able to reduce our rig count pretty quickly to where we sit now at 7 and 1 frac fleet of that. So I would say the low point on capital is going to be Q2, then Q3 and Q4 is reduced to get to that average frac fleet count of 2 to 3 capital would increase into Q3 and be relatively stable Q4. Now from a production standpoint, Q1, of course, would be the high point. We do have a solid wave effect from Q1 that flows over into Q2, but we did reduce our frac count down to 1 for Q2 where we sit currently.
And so if you consider the average production guidance for the year and the exit rate of 1 90 million to 1 95, that would signal Q1 would be your high point. Q2 would be lower and Q3 and Q4 to be relatively flat vis-Ã -vis quarter-over-quarter, but slightly lower than Q2. So fully that serves as a good guide.
That's very helpful. And then just my follow-up question. Scott and Rich, it sounds like -- and I'm not necessarily just saying distal but more broadly at the industry, it sounds like you're expecting any curtailments or shut-ins going forward to be voluntary in nature for the industry. So am I understanding that you all don't think there'll be any forced shut in due to storage constraints for the industry, not necessarily all?
My personal opinion is very little the shut-ins are voluntary. They -- people may say that, but a lot of companies don't have FT. And so they're being told by their purchasers. They can't move all down to the Gulf Coast because they can't sell it. So if you want to call that voluntarily, that's fine. But they're being told by the purchasers, they can't move their crude oil. And so we had the benefit to be able to move all of our crude oil on the Gulf Coast and export a lot of it. So that's [indiscernible] so what people say on their call may or may not be what's really happening.
Next question comes from is David Deckelbaum from Cowen.
Just had some of the follow-ups to some of the earlier comments you had made. Maybe this is a two part question, so I'll just leave it at that. But you issued the quarterly guidance or you removed the quarterly guidance for the second quarter. I guess you commented already that you're selling volumes already for June. And I think in Joey's comments, you remarked that June is looking a bit better than maybe expected.
I guess, what are some of the unknowns that you're thinking about now that or where is the period of max anxiety on the horizon here? Is it over the next couple of weeks in case storage fills? And then, I guess, in the second part of that question is, in the event that we do see storage filling, Scott, you alluded to, to operators not necessarily shutting in voluntarily. It seems like Pioneer has outlined that they don't see any issue being able to move barrels at this point.
So can you talk about what you think would happen to PXD's barrels in the event that storage does fill here? And then the earlier part of that question.
Yes, David, I think it's really a case of us remaining to be flexible. And clearly, we'll let economics drive. And so we've seen a resurgence in the oil strip, which has been positive. But we just see some more time pass to see how -- what happens with storage over the next few weeks to really make this. So I think that's sort of the key decision in terms of whether or not you have any more volumes at risk. And clearly, we're just going to adjust our program based on commodity prices.
In terms of moving barrels in FT, I think that's really the advantage of having FT that Scott talked about that we're able to take our barrels and then from the Permian Basin and on the Gulf Coast. And having a much broader market when you get to the Gulf Coast to be able to export those to the world market, there's just more demand. And I think ships are becoming more available, you're seeing people come out of the virus in Asia sooner than us, so demand is picking up. And these barrels really aren't going to get delivered until lost in those markets, and so they're forecasting what their demand will be at the point in time.
And so I just think it's an advantage that you look at from a timing perspective being on the Gulf Coast versus being in Midland. So I think the Brent market is going to clean up faster than the Midland market. So those that don't have FT are more to storage issues versus those of us that have that to give it to the Gulf Coast and can access the world market. I think you're just going to be better off as we work through these storage issues.
Next question comes from Charles Meade from Johnson Rice.
I wanted to follow-up on just a couple of themes that you've already touched on in your Q&A. First, at that kind of a $250 million or $300 million run rate that you guys CapEx revenue you're looking at for the back half of the year, can you want to take a stab at what your decline in '21 might look like at that constant CapEx rate?
Charles, it's Neal. If you think about our decline rate, and you've seen the benefits as we've spoken about the maintenance capital as we think about 2021, your decline rate obviously moderates in the subsequent year. So you would expect and we would expect a moderation in the decline rate from 2020 as we move into 2021.
So we've spoken about our decline for oil being somewhere in that mid-30s -- mid-to-high 30s, you'd probably gravitate to that mid-to-low 30s potentially. But over the course of time, that's right, you'll continually see that moderate setting up a more free cash flow environment for capital and cash flow.
Right. I get pointed about the PDP kind, I was more curious if you spent that $300 million a quarter would it be. But leaving that aside for now, it's actually going back to your -- to the -- you introduced this idea that you're not going to guide the POPs and it makes sense. But I wonder if you could -- you or you give a little insight into your thought process of, is there -- what are the scenarios where you might go ahead and complete a well, but then defer placing on production because of the price is available, what price is that?
Yes. I think we've seen a positive improvement in prices. And I think we would continue to put wells on. We fracked in this, call it, low 30s, high 20s is where we would put those wells on production. And so that's -- the activity levels that we're doing. We're going to take the economic signals as we get them over the next few months. But we're in that range, the economics are getting better, and we're going to -- we'll put wells on production.
Next question comes from Neal Dignan from SunTrust. Just
Only I just had quick one for first just on spending that I think about $100 million of what was it, the revised 1.4, 1.6 CapEx budgets for water infrastructure. So really, I'm just wondering around the water infrastructure, will that continue to be -- that seems like a very nice low run rate now. And I'm just wondering if that's going to be the run rate going forward? And is there a point now that you've really started to build that up or you consider, Scott, potentially monetizing those key assets?
Yes. In terms of the capital spend, I mean, the $100 million really is a big chunk of that still is the Midland water treatment facility is that basically most of that capital spend is into this year. So you'll see it even come beyond further as we go into additional years. And in terms of monetization, I think that's something that's off the table at this point, but something that we'll always continue to look at in the future. But today, the market is not there, they're not something we're focused on.
Very good. And then just particularly on your cash cost. It seems like they continue to come down, I think, in the slide that says decrease, somewhere around $140 million, $160 million. I'm just wondering, is there even further room to bring these down? And really, when you think about just some of the suspended D&C, is it based on, again, what some of these costs or what other sort of cost or factors are you putting into that decision to bring some of that other activity back?
Yes. I don't think, as Joey alluded to earlier, it's something that we're always focused on, and we'll continue to look at other things that we can do to bring our cost structure down to be as competitive as possible and generate free cash flow. So we're going to continue to look at across all the corporation in terms of what D&C, LOE, corporate overhead costs. We're going to continue to look at all those and how do we have the streamline the business as best we can and generate the most free cash flow.
There are no further questions at this time. I would now like to turn the call back to the host for any additional or closing remarks.
Yes. Thank you, everyone, for attending. Again, please be safe, stay healthy in your families, and look forward to seeing you all on the call in August. Hopefully, we can all start rounding at some point in time and seeing each other in person. So again, thank you very much.
That concludes today's conference. Thank you for your participation, ladies and gentlemen. You may now disconnect.