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Welcome to Pioneer Natural Resources, Fourth Quarter Conference Call. Joining us today will be Tim Dove, President and Chief Executive Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; J.D. Hall, Executive Vice President at Permian Operations; and Neal Shah, Vice President of Investor Relations.
Pioneer has prepared PowerPoint slides to 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 Webcasts.
This call is being recorded. A replay of the call will be archived on the Internet site through March 11, 2019. 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, Anna. Good morning, everyone, and thank you for joining us. Let me briefly review the agenda for today's call. Tim will be up first. He will discuss our solid 2018 results and our strong 2019 outlook, including many of the factors that differentiate Pioneer from our peers. After Tim concludes his remarks, Joey, will review our strong horizontal well performance in the Permian Basin, specifically our best-in-class oil production and our strong operational results. Further, Joey will discuss our commitment to environmental social and governance principles. Rich will then update you on our firm transportation commitments to move oil from Midland to the Gulf Coast and the financial benefits we are receiving. Tim will then return with a brief recap and commentary. After that, we will open up the call for your questions. Thank you.
So with that I'll turn it over to Tim.
Thank you, Neal, and good morning, everyone. We're excited to have a chance to talk about our 2018 results and our 2019 outlook. 2018 was a very strong year for the company and we look forward to an even better year that's more capital efficient in 2019 as we focus 100% of our efforts on our large Permian development plan.
If you take a look at slide 2, we delivered an ROCE for the year of about 9%. That's significantly up from the 4% level that we had in 2017. That's clearly a sign of high-return wells high-return margins that eventually hit the bottom line. Actually we would have been in double digits had we not liquidated hedges in the fourth quarter, which went directly to the P&L.
Our firm transportation contracts delivered fantastically in 2018, actually realized increased cash flow by almost $0.5 billion for the year $458 million cash flow uplift, which is a phenomenal benefit coming from the long-term taking. And the key being our ability to deliver on FT oil volumes to the Gulf Coast and for export and particularly that -- all that oil is priced on Brent-related basis.
Cash flow is up about 88% this year in 2018. We took some very important steps in the fourth quarter in particular divesting noncore assets that were not in the Permian Basin, of course, and our Pioneer Pumping Services.
As all of you have already been advised, we're also in the process of de-commissioning our Brady sand mine that will be completed very shortly here in the first quarter. And we continue to work on the Eagle Ford asset sale.
Our return of capital to shareholders continues to expand as part of our main goals, as we repurchased about $328 million of our $2 billion authorization that we put in place in December as over the last two months, and at attractive prices I might add. Again, yesterday we doubled our dividend. That amounts now to about a 700% increase over the last two years, an eightfold increase.
Finally, the steps we took in 2018 will be really important when it comes to 2019 in the sense that we in our 2019 plan can point to a significant CapEx decrease about 11% compared to 2018, while at the same time delivering a strong 15% increase in production. So, we're very excited about what 2019 holds when we can show that kind of capital efficiency gains.
Let's turn now to slide three. I think it's important to build on our success in 2018 and therefore, look forward to an even better 2019 with the capital efficiency improvement that I mentioned.
We had quite a good fourth quarter. Oil production for the Permian was toward the top end of the guidance range, as shown about 194,000 BOPD per day. And Permian BOE production was at the top end of the guidance. Of that almost $0.5 billion of FT, $173 million was achieved in the first quarter, sorry, the fourth quarter.
And then in addition to which we showed in the fourth quarter again reductions in Permian lease operating expenses. Very important, of course in today's world where with the commodities ended up in the fourth quarter to have a heavy focus on LOE reduction and we did just that.
As already mentioned, our cash flow was up significantly in 2018 versus 2017. And a significant amount of that was in the fourth quarter about 38% versus 2017. Again, we still retain one of the strongest balance sheets in the industry. And our debt metrics are shown there, very strong debt metrics at year-end.
Turning to slide four. This refers to our low cost of supply and really is based on our high margin wells that we can generate very strong returns through the cycle. So, those cycles allow us continue operating. And with 98% of our barrels or so receiving Brent-related pricing, it will further expand our margins and increase our cash flow.
You can see on this chart, as we look at actuals for 2018 and build from proved developed F&D, adding production cost and taxes, G&A and interest expense that our full about cost structure for horizontal drilling and putting these wells on production is $23 per barrel. That's why we can achieve higher rates of return even if we're in the low $50s on WTI.
And certainly the Brent-related pricing has helped, but it's also the case that this large resource base we have here, in the Permian Basin, is probably the lowest cost breakeven basin in the industry. And therefore, it bodes well for a successful future for the company.
Turning now to slide five. I've already mentioned that 2019 is going to be a strong capital efficiency year. We're again showing a material reduction in CapEx to about 11%, while achieving the mid-point of the range about 15% production growth compared to last year.
Activity will be slightly higher this year about 265 to 290 POPs. We're going to be averaging about 21 to 23 rigs. And despite all of that, we'll be reducing our capital about $350 million which also points to our capital efficiency.
You can see on Slide 5 that our well mix still is skewed pretty heavily towards Wolfcamp A and B. Spraberry, of course, increasing some additional tests in the Wolfcamp D.
Cash currently based on the $53 WTI case or a $60 Brent case is approximately $3.2 billion. When you compare that to our 2019 drilling and completions and facilities CapEx, the cash flow is easily enough to pay for that effort that budget of D, C, and F in addition to which our cash flow is very sensitive to oil price changes. With a $5 change in oil prices, we generate about $400 million of additional cash flow.
Turning then to Slide 6, improving capital efficiency is one of the main messages for today. And when it comes to 2019, the 11% capital reduction and then a 15% growth rate indicates such capital efficiency. The drivers are really related to some of the initiatives we achieved at the end of last year when we announced the divestiture of PPS to ProPetro.
That was completed on December 31st, so it becomes effective January 1st. And, of course, we are in the midst of transforming all of our sand supply to West Texas sand and that will be done -- essentially completed in the early part of the second quarter. And at that point in time we can show very significant cost benefits.
It's really important to point out that these are not sort of pie in the sky or wish list cost benefits. These are all based on contractual arrangements that is whether it's sand or whether it's our arrangements with ProPetro those are all under contract. And so these are readily achievable I feel like based on that.
For example our pressure pumping cost savings could be as much as in the neighborhood of $650,000 per well. It's simply because ProPetro runs an excellent operation. They're great company with a tremendous market share and that gives them efficiencies from the standpoint of their fixed costs and being able to spread that over more fleets.
They run a smaller organization at the top level than we had done and they run it very efficiently and lean. And so I think when you look at the effort that we put in place to arrange this contract with ProPetro it's going to be beneficial to both companies. In addition to which it saves us from CapEx that otherwise have to go into the fleets when we own them.
A sand is similar in the sense that it gets a big impact on the cost structure probably $350,000 to $400,000 per well. And this is going all to 100 mesh well, of course. But the 100 mesh sand also has another benefit and that is we can simplify our completion designs.
And what that means is we can reduce the amount of gel we've been using on heavier sands if you will and also the amount of surfactant need which will reduce cost by well by another $200,000. So, again, it's a product more of the sand change out on these wells than anything else.
In addition we're starting to see the benefits of our water infrastructure. And also we've been coming out of 2018 very high efficiencies on drilling and completions which when averaged over the whole year continue to benefit us in all of 2019.
We do see the potential for some inflation during the year. I think we'll be second half weighted as the opportunities for people to ramp up in connection with new pipeline space coming on stream could lead to increased activity and therefore might be a period of inflation. But I would call it minimal at this point. We're baking in about a 2% inflation rate in terms of mostly focused on the second half of the year.
So, the combination of all these will really drive an increasingly efficient program here. And with that robust production growth and material decrease in capital spending, I think, it bodes well for a strong year of capital efficiency.
And turning to slide 7, I want to talk a little bit about the five pillars or the five principles that we're utilizing here to focus on enhancing shareholder value. The first of course is focusing on returns. I've already mentioned this that our ROCE numbers are improving and that's because the returns on these wells are very strong as we continue to increase EUR per well. Joey will talk more about that in the subsequent slide, and we drive the cost down the wells.
One of the things we are trying to achieve, of course, is moving the capital to where we're generating free cash flow, and at the same time growing considerably and that's the focus on capital discipline.
The steps we've taken recently that is in December as well as yesterday vis-à-vis, the dividend increase show a focus on return of capital to shareholders. One major aspect of our company is the fact that we have a very strong balance sheet, perhaps the strongest in all the energy patch and it gives us a lot of financial flexibility going forward.
One of our tremendous benefits, of course, is our inventory, inventory of low-risk wells, high-return wells that give us a runway or a pathway to long-term organic growth. And what I want to do is address each of these five in some subsequent slides. We'll use some more details on actually how we're going to accomplish that in the next few slides.
So first let's focus on that idea of the focus on returns on slide 8. And what you can see on slide 8 is that there's a couple of benefits we have here. Number one, when you look at ROCE, you can see that Pioneer is above the peer average in terms of ROCE for 2018. And one of the reasons that's the case is, because we're generating corporate returns that are high due to the fact we have low-cost acreage in our assets, low-cost acreage being that which -- that was really put together in the 1990s effectively. We've done very few acquisitions.
If you look at the graph on the right, you can see many of our peers have engaged in very expensive acquisitions, some of them up to almost $90,000 an acre. Our average bases on the balance sheet for our acreage is $500 an acre. So what you can see at the bottom is that if you're going to amortize that across well locations, the cost that we amortize to a well for unproved acreage is $21,000 a well.
If you look at the most expensive of the acquisitions shown here, the 15th acquisition on the right, you're going to be amortizing again $3.7 million per location. And so it's going to give us a tremendous advantage going forward. The fact that unlike our peers, we've been able to use our low-cost bases as an advantage. That's going to continue to give us a return advantage at the corporate level. And in addition to which that low-cost basis can support many years of growth generating higher returns.
Going to slide 9 and now focusing on capital discipline as the second topic. This chart is similar to the waterfall chart, you see some other companies utilizing it sort of like this. But on the left you see that our cash flow at about $40, if it were to be that price on a WTI basis would be that which would be sufficient to cover our maintenance CapEx about $2.2 billion.
When you look at a $53 case, which is essentially what this whole presentation is based on, you can see it allows us to do two things. One is to increase our dividend, which we've shown and we've done as of yesterday; and also generate growth, the growth in production ranges that we're talking about for 2019.
It does give us other opportunities of course to the extent that we have prices well above that $53 case. We've got a lot of different options, whether it's share repurchases or other investments just building the balance sheet additional growth or what have you. The answer is, we have a lot of financial flexibility and a lot of operating flexibility. We actually get a case above $53 oil.
Slide 10 then is the next of those five topics. This one's focused on a return of capital. As I've already mentioned, we've had a substantial increase in the return of capital to shareholders. It's a main mantra of ours. Our dividend is eight times what it was in the first quarter of 2017. And we repurchased also as I said over $300 million of the $2 billion authorization. So far this year and combined with the -- this combining the dividends and also the share buybacks, we've generated a return to shareholders of 1.9%, roughly about 2% in 2019.
And turning to Slide 11. This is a balance sheet-related slide. You can see where the company sits in terms of its relative measures of debt, in this case debt-to-EBITDA on the vertical axis and debt-to-market cap. You can see under any measure basically even among the largest companies in the industry we are -- have the strongest balance sheets basically in the industry. Net debt at year-end of just under $1 billion reflecting a substantial amount of cash and investments on hand $1.4 billion. And then of course that gives us lots of financial flexibility going forward as it relates to the next set of decisions to be made.
Now another slide, slide 12 talks about the repeatability of our program. We really have what amounts to as an unmatched footprint, unmatched in terms of scale, in terms of continuity. And the fact is our wells have improved year over year over year and they continue to do so. You can see that on the graph on the top right. 2018, you still see, this is where all the wells drilled.
Again increases in terms of productivity which is phenomenal that we're able to do this many years and we've been able to do that. Of course it has to do with the fact that we have a tremendous data set. Of course we had drilled 5000 to 7000 vertical wells over the years and plus we've now drilled some 1200 or 1300 horizontal wells. We have the largest data set of any company and that allows us with that proprietary data set to do all kinds of evaluations and appraisals. That's the best way to develop these wells and to complete the wells including using machine learning.
So it's a methodical approach to appraisal. That's really been the keys to that. And it's allowed us to year after year increase the resource available to us. So when you match that up with capital efficiency and you realize we're actually increasing EURs per well that's a formula for a significant improvement going forward. And again, we have acreage to do so. It's very contiguous and as a result gives you a lot of cost efficiencies related to that.
What I'm going to do now is pass it over to Joey and he's going to give you a bit of an update on operational performance and also an update on some of the recent well results.
Thanks Tim and good morning everybody. I'm going to be starting out on Slide 13 where we want to deliver two main message, both of which speak to our ability to sustainably deliver strong margins. On the left-hand side, you can see that on a gross production basis Pioneer has the highest oil percentage in the Permian Basin. And this is of course the foundation to our ability to deliver in our strong margins.
And then on the right-hand side and of equal importance, you can see that since 2016 Pioneer is the leader in cumulative oil production in the Permian. Again these two facts combine and speak to our ability to consistently deliver robust margins and generate strong returns.
Now I'm going to be turning to Slide 14. Last quarter, we updated you on our first Stackberry test in Western Martin County. Very similar and encouraging results from our second Stackberry test in Central Midland County. Here we had eight wells drilled and completed as one project.
Wells on this pad are outperforming previously drilled Spraberry wells in that same area by about 34%. Of course this speaks to our advancements and our completion strategies. But I believe more importantly, it speaks to our ability to deliver strong well performance in full development mode.
These results also drive our strategy to implement more large-scale projects in 2019. We have our third Stackberry test online in Martin County and it is on production and cleaning up. And we'll be reporting on that in the Q1 call.
We've also continued our success in the Wolfcamp D, we POP’d another Wolfcamp D 2-well pad in the Western Glasscock County. These wells have only been online for a few weeks but showing very strong early time performance with average 24-hour IP on these two wells over 4000 BOEs per day with a 72% oil mix. And of course we will be continuing our Wolfcamp D appraisal work in 2019.
Now shifting to slide 15. Here we want to highlight our commitment to thoughtful planning and sustainable practices. In 2019 you see that approximately 40% of our pads will be four wells or larger compared to only 10% in 2018. These larger pads of course will help us reduce unit cost due to the resulting Drilling and Completion efficiency gains.
We also continue to leverage and evolve our automated water infrastructure and we remain committed to reduce our usage of freshwater. At the end of 2018, we were using about 10% to 15% of our completion needs for being supplied through recycled water. And we're going to stay on that journey in 2019 and plan by the end of the year that about 30% of our needs will be supplied through recycling.
Combine this with our current and future effluent water sources from the cities of Odessa and Midland and this positions us to significantly reduce our use of freshwater while decreasing our cost of supply. All these things combined with our other centralized facilities allow us to drive down overall development capital.
Now I'll be moving to slide 16, really just a very simple but important message here. Pioneer is absolutely committed to safe, responsible and sustainable operations. As you could see from the previous slide, the great news is, is that sustainable practices go hand-in-hand with running efficient operations.
And we just want to highlight that for great insight into some of these practices and the proactive measures that we're taking here at Pioneer to operate responsibly we'll just direct you to and take the opportunity to read our 2018 sustainability report where we outlined some of these practices.
And so with that I'm going to pass it off to Rich.
Thanks Joey and good morning. I'm going to cover slide 17 where you can see that one of the benefits of long-term planning has been entering into firm transportation arrangements to move our oil to the Gulf Coast.
The ability to sell this oil at Brent-related pricing has had a very positive impact on both margins and returns in 2018. For instance during the fourth quarter, we moved about 90% of our oil to the Gulf Coast which had the effect of increasing our oil margins by over $9 per barrel.
For the year our per barrel margin was improved by over $6 as you can see on the upper left corner of the slide where our realized price was $64, including the benefit of Brent-related pricing versus the Midland market price of about $58 per barrel. If you put this on a cash flow perspective, these sales added an incremental $173 million in the fourth quarter or $458 million for the year.
During the fourth quarter we transported about 175,000 barrels a day to the Gulf Coast about -- of which about 80% of those barrels were exported internationally with 60% of those barrels going to Europe and 40% to Asia.
Our transport volumes do increase starting January 1 to 200,000 barrels a day. And based on forecasted price differentials between Midland pricing and Brent pricing, we are forecasting a first quarter uplift of approximately $40 million to $100 million for the quarter or $2 to $5 per barrel. Once again, you can see that the firm transportation is allowing us really to get Brent-related pricing on most of our oil production and most importantly, improving margins and returns.
So with that, I'm going to kick it back to Tim for a few closing comments.
Thanks, Rich, and I appreciate everybody being on the call. We're going to turn to Q&A in just a minute. But, again, I want to focus everyone on the fact that there are really five pillars or five key aspect of what we're going to do to drive results here and drive performance. And they are, again, our focus on returns and we are heavily focused on this.
And I think we have a tremendous advantage with that low-cost basis acreage that I referred to earlier, as well as the fact that we've got very high-return wells. And we want to push the company towards a free cash flow-generative model, of course, and at the same time be growing. I think those are a good model, when coupled together.
Return on capital to shareholders we're showing to the market that that's important to us, as we continue to increase that. And I think that would be the plan going forward as well. We already have one of the best balance sheets in the industry and plan to keep it that way, with low leverage, because you never know what's going to happen with commodity prices. We certainly want to be responsive and have the right balance sheet to be able to deal with any outcome and I think that's the position we're in today.
And finally, we can continue to repeat this. We have quite a large inventory of wells to drill over the next many years. And basically what's going to happen, this growth is going to occur without acquisitions. And we don't really need to do large acquisitions like some of our peers to grow. And that then preserves our low-cost basis in the acreage. And it's essentially organic growth from the drill bit.
And I think that's the best way to proceed there from the standpoint of returns and all of these goals. So as you can tell from our presentation, we're very excited about 2019. And it's going to be a year in which we substantially gain in capital efficiency, which is something we're very heavily focused on.
So Anna, I'm going to stop there and we're going to kick it over to Q&A.
Yes, sir. Thank you. [Operator Instructions] We will now take a question from Doug Leggate with Bank of America Merrill Lynch.
Thank you. Good morning, everybody. Tim, can I congratulate the IR team on a tremendous update to the presentation deck. I love the new format.
Yes. The new PXD look, Doug, okay? So it's all good.
All right. So with that, I've got two questions if I may. Tim, first of all philosophically and we obviously believe your share price is tremendously undervalued. But while you were talking, I was just looking at the chart. Your share price today is pretty much where it was in March 2016. Your production has doubled in that time frame. Your net debt is flat and the oil price is actually higher than it was back then.
My point is, the market clearly isn't paying for your business model. And I'm just curious, with the share buyback announcement, you're still looking at pretty punchy growth, not a lot of free organic cash flow. Have you considered, and if not why, the right model might be to slow down the growth and really have a hard look at buying back shares more aggressively, given that the market seems to pay for growth per debt adjusted share as opposed to absolute growth in marathon today, but the case in point, looking at their share price reaction?
Well, I think, Doug, first of all, we are slowing down growth, if you look at this year compared to the prior two years, we've been well into the 20s in terms of growth percentages. We have moved this down. We have a range now which centers on 15%. Obviously, we can ratchet within that range at a moment's notice. It's based on how much activity we want to execute on. But fundamentally, we've taken significant steps to increase basically return of capital to shareholders and we wouldn't have a $2 billion share repurchase plan if that wasn't the case. But I think we have to go further.
I mean, I think, if you look at our dividends announcements yesterday, we still have a dividend which I believe will be subject to further increases in the future, as we evaluate our business model and go forward. We have some room before we get up to even what I will be considering that which would be near some of our peers that we respect. So, I think the answer is there's room to move forward along those lines.
Okay. I guess just as a point of clarification. The buyback program, if I look at the strength of your balance sheet, I guess this one is for Rich probably, but when you think about the right level of debt-to-EBITDA coverage and given where your share price is, should we expect you to exploit the balance sheet a little more to take advantage of share price weakness or is that not the way to think about it? In other words, not out of free cash flow, but buying back shares out of your balance sheet essentially.
Yeah. When, I think when we approved the share repurchase program, it was predicated on knowing where our balance sheet was at that point in time. I mean, obviously, we're going to manage the company to low leverage like we've done in the past, given the volatile industry we live in. And we're just going to keep those debt metrics in that less than one-time debt-to-EBITDA type levels. But we have clearly a great balance sheet today that allows us to take advantage of the valuation of our stock when we think it's appropriate to buyback aggressively if need be.
Okay.
Yeah, I would only add that, if you look at what is the ultimate model, it's to actually generate excess cash such that we can actually decide regarding dividend increases or share repurchases from that incremental cash above our capital needs. We're on a track to that exact outcome.
And it’s definitely a long-term goal.
I don’t want to hold all the questions, guys. I’ll let someone else to jump on. Thanks. I know it’s not an easy question to answer Tim, so thanks for taking it. Appreciate it.
We'll now take our next question from Arun Jayaram from JPMorgan.
Yeah, good morning. Tim, the focus today I think has been where the puck has been in terms of higher D&C cost in 2018. Your outlook suggests where the puck is going is towards much lower D&C cost. Just wondering what kind of confidence do you have, can you give investors this morning that you can meet this $3.1 billion to $3.4 million kind of CapEx number given what happened in 2018?
Yeah, first, let me comment on 2018, because I know we did come in a little bit high on capital. And so, the primary, one of the primary reasons for that was the fact we were so efficient. I mean, this is a strange conundrum, but we were very efficient in terms of our drilling and completions efficiencies, which means we got more POPs done and that's a good thing. I mean, that said as our capital run rate increases as a result of that. And we also had some other land-related expenses and gas prices expenses that hit in the fourth quarter from what is going to be construction projects to end the year and the first half of the year.
And so, when you look at that, those are things that we have essentially behind us from the standpoint of the current run rates. What I would simply say about 2019, all the stuff is basically contractual. We have contracted the sand. We have contracted the pressure pumping. We have specific price books in every case. We also then as a result of using the finer sand then have cost savings because as I mentioned earlier regarding gel and surfactant and so on. And as a result, when you consider other efficiencies that we're bringing to bear as well and we have those efficiencies occur throughout the entire year that ended last year, we can point to various specific reductions. And so this is not as I said a pie-in-the-sky cost reduction plan. This is contractual and I guess the main point.
Great. Just a follow-up on the 2019 program. 265 to 290 POPs, wondering if you could provide some details on kind of the mix between North and South and the different intervals. And just a little follow-up here. As you switch to the 100 mesh sand versus gel, Tim, is there any changes that you perceive in terms of well productivity given the lower cost to a more simplified completion design?
Yes. On the last question I think what we've seen is that the lower -- the finer mesh sands actually has produced very strong results. There were no difference in results. And as a result, there's no reason not to take advantage of the cost savings. Now, we're continually watching over that, but I believe we already essentially proved after -- now like I said multiple quarters we've been watching not only our data, but pure data. On your question on the rigs, well, I can kind of look at more rigs. We'll be probably in the neighborhood of five rigs in the South and the balance will be in the North, but you can translate that to POPs.
Do you have anything further?
No.
Okay, great. Thank you. We'll now take our next question from Bob Morris with Citi.
Thank you. Tim, nice to see the initiatives on the well cost reductions here. As you look out to 2019, are there any further initiatives in the works to further reduce the well cost here going forward or it will be pretty much all achieved?
Every day – Joey, you might want to comment. Every day we're trying to reduce the well cost Bob. And these are some major chunks we've taken out of the year. But there's other things. Joey, why don't you comment on some of the other initiatives?
Yes, Bob. This is a focus every day. We're not just taking advantage of the contractual realities that are going to significantly make an impact. But I was actually reflecting on some numbers this morning. When you look from 2017 through 2018 and we reduced our cycle times by almost 20% on the drilling side and 10% on the completion side of course those are -- it doesn't necessarily translate 20% faster, doesn't necessarily mean 20% less, but it does mean less. We're continuing in that momentum going into 2019. All those things are -- we're making these improvements by design, by focusing on NPT and eliminating waste from our supply chain and everything that we can do to get the most effective and most capital-efficient operation that we can. So absolutely, that's where the hard work is making the contracts be different. That's in the rearview mirror and now we've got to continue to work hard to drive down other cost. And we've got lots of things in the works to do that.
That's great. And congrats on the initiatives you've accomplished here. The second question is just on the source of the 2% cost inflation you expect this year, a lot of your Permian peers are pointing to a 5% to 10% cost deflation this year. So just curious a little bit about what gives the source of the 2% cost inflation that you mentioned was more in the second half of the year, but where that comes into play?
Yes. Bob, I think we're really referring to because we're talking about average numbers for 2019 is the average is 2% for the year. You could easily have 4% or 5% by the time the end of the year is here. That means, you'd be averaging about 2% and I think it's largely driven by labor cost. And as I mentioned in the commentary earlier, it very well could be because of the heightened activity. You see the DUC count numbers just like I do and you realize that once the pipeline of space is unleashed, there should be an increase in activity and that could lead to some inflation.
We certainly haven't seen much yet this year. In fact, we've seen some reductions in certain of our costs including our rigs. This is another point that Joey didn't make, but our rig costs are lower just because they're tied to oil prices than they have been last year. And so I think being conservative here is definitely a positive. I mean I feel like it and that's kind of what we're trying to achieve. But I think 2% made on average maybe a reasonable expectation. It doesn't really disagree with what others are saying.
Okay, great. Thank you and nice quarter.
Thank you.
We'll now take our next question from Charles Meade with Johnson Rice.
Good morning Tim, you and your team there.
Hi Charles.
You've touched on this just briefly Tim in response to an earlier question but I wanted to go back to this new completion design. You guys put a lot of detail in here about the savings you're going to get on the capital side. But you also mentioned that you're not seeing any change on the well productivity side.
Can you talk about what you thought you might see what you've seen to date and if we on the outside looking in should expect -- or what if anything we should expect different over the course of 2019 as these wells come online and produce?
Yes. I think, first of all, when you're talking about the completion design, what's changed, of course, this year, in particular, this should be the first year that 100% of our completions are just sort of dialed into specific types by zone by area.
In other words there's not just everything 3.0-plus or everything is 3.0. It's -- there's a whole mixture of different completion techniques. So -- and that's what you hope actually leads to incremental improvement of the EURs just like we've seen in the last four years.
And so I hope we can show in other lines it exceeds the 2018 performance line by doing just that. And again it's a product to a great extent of our machine learning efforts to understand exactly what's the right formula to make these completions more efficient.
So, I think we're not really bucketing the completions in any specific versions, but rather we're just trying to optimize across the whole program.
And Charles I would just add one thing as an example. Whenever we talk about the contractual savings that we'd get from shifting to 100 mesh West Texas sand, there is a cause and effect relationship that goes on in that decision and there are similar ones.
And the sand that we're using previously is a coarser sand. And coarser sand requires higher viscosity fluids in order to deliver it. And with the lower mesh sand we're able to reduce the amount of gel that we use which is substantial savings in cost. And we're able to deliver the same amount of sand for less cost. So that's an example of how some of these contractual changes also have a technical change but has no impact on well performance.
Right. And I guess that's really the key. There's no impact to the well performance from this change of the grain size.
Correct.
That's across our data and also our peers.
Got it, got it. Thank you, Tim, that's -- Joey, that's what I was after there. And then the second thing if I could ask about this Stackberry -- Stackberry test and how it kind of interacts with your move to more big pads in 2019. It looks to me like this big well Stackberry test is one of the bigger pads that you guys have used or are using.
So, is that something that's specific to this -- to the need to co-develop those three zones? Or is this more something we should look for that you can use in your Wolfcamp A and B program, where there's efficiencies just from having the rig and completion crew on location longer?
Yes Charles. The answer to your question is that, does not only applies to the Stackberry development, but we're also going to be doing several A and B co-developments. And even in the future, towards the end of 2019 we have some Stackberry combined with A, B and D co-developments.
I think it's really important to point out that we do that for two reasons; one, for the operational efficiencies that you mentioned. But also we believe that's the most optimal way to develop these wells and avoid the parent-child impacts that you hear a lot of the operators talking about.
So for us it's a win-win. The only downside is these larger pads do have longer cycle times. But the upside from an EUR perspective and from a cost efficiency perspective far outweigh the cycle times that you endure.
Got it. Thanks for the added detail.
We'll now take our next question from Brian Singer with Goldman Sachs.
Thank you. Good morning. My question is a follow-up on the topic of initiating and executing on the CapEx plan. First to start, I think Tim you mentioned that the construction spending that partly impacted fourth quarter CapEx is continuing into the first quarter or the first half. So just to set expectations on the budget that you've said what percent do you expect to be spent in Q1 just to make sure there's no surprises on the trajectory?
Yes. So I think first of all as we know as we try we're going to get the sand savings until into the early part of the second quarter. So that's an example of things we're going to have a run rate that's higher, and at the same time we've got certain costs to hit the first quarter including Targa-related cost. So Neal you want to give more detail and answer that?
Yes. Brian as we were looking at our rig ramp and other rig trajectory moves throughout the year, the exit rate on that rig count extends really through that first quarter until we really start dropping rigs and we kind of normalize where that average day on the full year. So that too also drives 1Q spending versus the fullness of 2019 to be somewhat higher.
Got it. Is there any greater clarity on the percentage you could give again just to make it a little bit more clear?
Yes. Your run rate for 1Q is going to be -- it's definitely going to be higher than your Q2, Q3 or Q4 run rate. So - and obviously here like we're talking about the rigs. We've got an additional rig -- few rigs running in based on the exit ramp rate. And then you've got the additional spending related to Targa as well.
But we can definitely help you with your modeling as well offline. But you can think about the cost for -- to running additional rigs coming out of the year versus the rig decrease throughout the second and third quarters somewhere around -- you could think about somewhere around the $150 million $200 million.
Great, thank you. And then my follow-up is a little bit bigger picture but with regard to the same CapEx topic. The mindset of the company seems to be now much more the prioritization of spending within cash flow/delivering free cash flow. You're restructuring the sources of past volatility on the sand and the pressure pumping front.
I wondered if you could just talk to the cultural mindset of capital execution and making sure that is throughout the company. Can you speak to your efforts to ensure execution and that $3.1 billion to $3.4 billion won't need to get raised later in the year?
Yes, Brian. I mean, this is obviously a focus for us in 2019. We deal with these things both organizationally and through initiatives. So we have a dedicated team that's daily focused on looking at our daily cost and ensuring that the cost that we've projected will be met in 2019. We're making evaluation every single day on whether or not we're meeting those targets.
So my experience has been as leading operations for over 20 years is that what gets focused on gets fixed. And we're certainly taking that seriously as an organization and it will be our primary focus.
I think it's also important to say that a lot of the things that we've been doing to learn and understand how these reservoirs work together, a lot of that stuff is behind us. As Tim mentioned earlier, we're dialing in on what our completions are, so there's a lot of -- not of -- there's not a lot of uncertainty onto what our execution plan is.
So having a consistent plan in front of you also goes a long way towards helping you understand what your costs are going to be. So I think all those things combined together are going to lead to a greater capital discipline in 2019.
Appreciate that. The range of CapEx is appreciated. So thank you very much.
Sure, Brian.
We'll now take our next question from John Freeman with Raymond James.
Good morning, guys.
Hi, John.
Hi. Just following-up on Brian's question and Doug earlier just to make sure that I'm sort of thinking about this the right way sort of the context of a previous kind of $110 million plan, and the increasing importance on the free cash flow. So on that slide 9, the kind of waterfall slide that you show where you basically say above the $53 a barrel number that is embedded in your current plan and shows the amount of free cash flow you have above that and the options for that cash. And you've talked about previously like a $5 improvement in oil the prices $400 million of incremental cash.
I guess just for 2019, if theoretically in oil price, it's $5 higher than what your plan is kind of how you think about how much of that goes to free cash flow versus the previous kind of plan, which was kind of we should always assume kind of two incremental rigs each year roughly to get to that one million barrel target. Just sort of how we think about the trade-offs of the two?
Well, first thing I'd say is, we don't really consider the million barrel target as the main driver here. We're trying to focus on capital discipline and making sure we deliver returns at the bottom line and continue our focus on free cash flow generation. Let me state that first.
But when you take a look at how that money would be allocated to the extent we -- a $53-plus case in terms of WTI or $60-plus Brent case, we've got a lot of different options there. I think the real question is, how sustainable will that price be? In other words, are we in a different environment, we're in a $70 Brent case that would change some of our ideas regarding all of the different potential areas to allocate the capital.
In terms of 2019 decision-making, we have put a range out there of capital to make sure that everybody understands it. We haven't made any decisions on adding rigs yet in 2020, but there is a range and a capital for us to consider that. So that will be something we look at as we go through the remainder of this year, particularly as we get into the summer. But the range of capital is intended to cover anything we might need to add if we decide to do so in 2019 to address a 2020 run rate.
That's great. Thanks. And then just my follow-up question, given that you've got about 40% of the activity this year on these larger scale projects versus the 10% last year. I was actually impressed that the POP times didn't appear to materially go up as you would normally sort of assume with the bigger projects. I assume that's maybe some of what Joey was talking about with the big improvements on the drilling and the completion cycle times. But I'm wondering if you can just kind of give us just rough numbers on how those larger-scale projects kind of would -- the POP times kind of roughly look like on those versus the rest of the plan. I am assuming as we go forward, we're going to continue to have an increasing amount of the activity on these larger-scale projects when we think about 2020 and beyond.
Yes. John, the way that I would look at it is typically speaking a three-well pad takes about 170 days to POP. And for every well you add to a pad, you're basically going to have 30 to 40 days. And we've got a mixture of about 50% still three-well pads in 2019. So it's important to keep some of those three-well pads in there, so you keep the consistent cycle of POP-ing wells.
And then about 40% of our plan will be four-well pads and greater, but only a small percentage of those are seven and eight-well pads. So I think that it just goes to show that a good mixture of three-well pads and larger pads gives us the ability to deliver consistently on POPs as opposed to a whole program full of eight-well pads.
And I think the average in site would be about 150 days. We're going about 200. That accounts for all that average of all the different types of pads.
Yes.
Thanks guys, appreciate it.
Thanks John.
We'll now take our next question from Jeanine Wai with Barclays.
Hi, good morning everyone.
Hi Jeanine.
Hi. I guess back to the 2019 guide following up on a few other questions. We've been seeing a bunch of 2019 outlook being anchored at $50 WTI which has become I mean like the kind of thing like your gold standard for showing free cash flow at lower oil prices. And we recognize that $50 could very well be as arbitrary as $53. But what was the thought process on using $53 WTI as a planning deck? I mean this is really kind of more of a messaging question versus an operational question. Is there something operationally that's driving the 21 to 23 rigs for this year versus further moderating activity?
Well first of all on your first question, the reason we have used $53 is only because it helps on the parlance of how you discuss United States business. But the fact is all of our business is based on Brent crude oil prices. We're actually focused on a $60 Brent case, so let's start there. So we'll just use the generic differential of $7. So it's more like the parlance or the IRSP if we put -- when we say $60 Brent we really are just translating that into $53 WTI. And the rig count of course is just a product of how capital-efficient we are. We were able to actually use less rigs to achieve more outcomes in terms of POPs and that's fundamental to the idea of capital efficiency.
Okay. Great. And then my follow-up question is related to capital efficiency. As we look forward to 2020, how do you see your corporate breakeven trending from the current $53? And are the primary drivers of that kind of progressively larger and larger pads? Is it you continue to see more incremental upside from completion improvement that you're always working on? Or is there structurally kind of more things that you're working on to reduce nonproductive CapEx?
We're doing all of the above. NPT is a huge drain in our business and so we have a heavy focus on reducing it. And just back to what Joey said it is focusing on the details regarding -- every detail of the drilling and completion process, so as to reduce nonproductive time. But it's across the board. It's all different types of efficiencies we're looking at to make sure we can achieve at a high level.
Okay, great. Thank you very much.
We'll now take our next question from Ryan Todd with Simmons Energy.
Thanks. Maybe a follow-up on some of the earlier questions. We hear from -- I don't want to beat this too much, but we hear from some of the market that increasing interest in the sector from investors may require a free cash flow yield that approaches that of the broader market or closer to 5%. Do you view that as a reasonable outcome for Pioneer down the line? And if so, do you envision that as something that it will happen organically on its own as you continue to get more efficient? Or do you need to proactively continue to reduce capital outlays and growth?
I think it will happen to us on its own. Now the question is what day it occurs for us, right, because we have certain things that we're spending money on right now that are necessary that would put that day off. So the example is the Midland water treatment facility. That facility is going to be materially finished by the end of 2020 and it will be done. At that point in time you've got a significant bump to your available cash flow and therefore a push towards free cash flow generation.
We have a certain cost, which has to be paid in the next couple of years including for example some of the Eagle Ford deficiency fees that are the same -- over the same -- that is to say that there are payments that have to be made. And, therefore, when those are done it gives us a significant shot in the arm on free cash flow generation capabilities.
And so the main thrust though should be actually drilling high rate of return wells on a repetitive basis and a growing basis and that's where you really get your free cash flow yield, especially if you have reasonable commodity prices. What that means is you have margins, which support the business. That's really one of our key focuses. The rest of these things are going to occur. We're going to finish the water plant. We'll finish our deficiency fees and so on. It's really the generation of high-margin wells, which is really the ultimate goal, so as to then generate a free cash flow yield, which is competitive.
Right. I appreciate that. Maybe one other, I know we asked you about this periodically but given the continued success of your appraisal programs like the Stackberry project derisking, the Jo Mill, the lower Spraberry and the Wolfcamp D combined with a slightly moderated growth rate you already purely in inventory and resource depth is quite enormous. At what point might it make sense to carve off additional portions of acreage and maybe at the bottom end of your portfolio and monetize those?
Yeah. I think we're looking at -- we look at that all the time. In fact there's a couple efforts underway to do exactly that and look at -- in any portfolio of course you have a tale of opportunity which isn't as strong as this – as your best projects. And so therefore, those are being looked at in terms of the potential for divestiture. Also of course, every day we look at the situation vis-à-vis our inventory. And we have a tremendous inventory and we look at situations where wells won't be drilled for quite a long time at the inventory. And it's certainly, an opportunity to look at to monetize some of the things, we won't get to for three decades let's say. So those are certainly under consideration.
Of course, it depends on exactly what the market is. Right now, the market is not terribly strong for the sale of acreage. And so that's a little bit of a governor for today. But that said, our real money has been made in trades. We traded 5.7 million acres last year, which added basically 36,000 acres. But the bottom line is everything is under consideration whether it's selling certain acreage, because they're lower in the inventory or because it will be a long time in coming. We're going to do whatever is in the best interest of our shareholders.
Thanks, Tim.
We'll now take our next question from Matt Portillo with TPH.
Good morning, all.
Hi, Matt.
Tim a question regarding capital allocation, there's been a lot of focus this morning on the D&C side of the ledger. But just curious how the market should think about investment in gas facilities and water infrastructure over the next few years versus the $300 million guidance in 2019?
Well, certainly I think I've addressed water facility. We are essentially completed with our water project in Midland, which is going to afford us relatively very cheap when we say water supply of 240,000 barrels a day after the investment in this facility. That is done as of 2020. So you can count that as already up, as a significant reduction in facilities. Right now, of course, we've had a great relationship with Targa in processing gas in the basin. And of course, we are going to need more gas processing in the basin in the future, so we'll have to evaluate the further investment in that. But for the time being, we've got two new plants coming on here in the first and second quarter.
Great. And just a follow-up question, around cost savings on a go-forward perspective. You've laid out very clear line of sight to some of the contractual changes. I was just curious, is there any incremental color you could provide on the potential shift as you move to these larger pad developments and ultimately what that might mean in terms of some long-term improvements around capital efficiency?
Yeah. Matt, we're – I mean obviously whenever you do the same thing repeatedly on one location it has several synergies. One is just the repeatability of drilling rig going down the line and drilling more than two or three wells at a time. But also the ability to have reduced facilities and flow lines and things of that nature. So pad by pad, it's different.
But I would say just as a minimum benchmark that our expectation is the full cycle we would expect to save 5% to 10% full cycle on a larger-scale development as compared to some of the smaller ones. Again, the thing that I emphasize is that that's great on an absolute basis. But the thing that you're countering it with is the spud-to-POP cycle times. So we try to balance what -- where we're gaining the EUR is where another big benefit comes from whenever we're codeveloping these wells. So we're trying to balance all those things in order to get the most capital-efficient program we can each year.
Yes. And I would only add that we calculate that as of the end of the year 2018. We're about two-thirds done with the entire field development. There's one-third more to do. It's going to take a few years to get that done as it already has taken a few years to get to the first two-thirds done. But there's line of sight a few years from now where incremental capital going to basically would amount to facilities such as all the tank batteries, flow line necessities and also related to saltwater disposal would've been substantially completed. We don't have an exact target date on that. But I can tell you we calculate we're two-thirds done.
Thank you very much.
And that concludes today's question-and-answer session. Mr. Dove at this time, I will turn the conference back to you for any additional or closing remarks.
Thanks, Anna. We appreciate everybody taking time to be on the call. And we look forward to 2019 as being a stellar year. We're really focused on all the things we've mentioned. And I'm really looking forward to our performance for this year. And I think everyone will be pleased when we have the same call a year from now. And in the meantime, hope you enjoy your Valentine's Day. Thanks very much.
And once again, that does conclude today's conference. We thank you all for your participation. You may now disconnect.