Pioneer Natural Resources Company (PXD) Presents at Bank of America Merrill Lynch Global Energy Conference - Transcript

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About: Pioneer Natural Resources Company (PXD)
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Earning Call Audio

Pioneer Natural Resources Company (NYSE:PXD) Bank of America Merrill Lynch Global Energy Conference November 15, 2018 2:50 PM ET

Executives

Richard Dealy - Executive Vice President and Chief Financial Officer

Analysts

Douglas Leggate - Bank of America Merrill Lynch

Douglas Leggate

So we are going to get straight on to Pioneer Natural Resources. Neal is very kindly to arrange for the guys to come down. So Neal, thank you for having Rich here. Rich Dealy, CFO of the Company and we’ll hand straight over to you. And ideally Rich if we do about 20 minutes on the presentation and then we'll go to an open Q&A, if that's fine. I apologize for starting late folks.

Richard Dealy

Thank you all. I'll start here with the forward-looking statements. So I’ll read that quickly. Really Pioneer at a glance, so for those of you that – I know most of you follow it. So I won't spend much time on this. But after we get completed with the divestitures we announced earlier this year will be a 100% Permian pure play. And what that means is about 750,000 gross acres in the Midland Basin, about 20,000 – over 20,000 drilling locations to be drilled in the basin. And all of these, we probably have 35,000 in different commodity price environments that we can drill.

As you can see here in the lower right, our production in the Midland Basin as an operator about 383,000 BOEs a day, the largest in the basin by a factor of about three. On a net basis, we're about 288 MBOE per day out of the basin in the third quarter. All the stuff that we're drilling today is low cost, high return horizontal wells, and we have very low average royalty across the basin. And as addition, very low cost acreage basis we got into this stuff in the last 20 years ago, so our probably average cost basis is $300 to $500 an acre.

From a balance sheet standpoint, excellent condition, probably one of the best in the industry. Cash on our balance sheet at the end of September of $1.7 million. We've got capital asset divestitures that proceeds are still to come in, so that will grow. Net debt to forecasted operating cash flow of 0.2 based on our forecast for 2018 cash flow.

Running 22 rigs today, we’re planning on adding two more in December to take us to 24 as we move into 2019. We expect to pop about 250 to 275 wells this year. We're on target to do that. We have put on production, probably of that 60, 39 we put on production, we did 44 in the second half of these bigger completions. These are basically 2,500 pounds of sand or more completions. So we are front-end loaded in terms of the third quarter versus the fourth quarter on that. We'll put other 16 on here in the fourth quarter.

I did talk about earlier – we announced earlier that we did U.S. Silica contract for West Texas Sand. That's a contract that will kick up in 2019 for 1.4 million tons of sand in 2019 and 2 million tons of sand thereafter to support our drilling program. We went to West Texas Sand because of the cost. If you look at that cost, it’s about half of what it is at Brady, Texas today.

Those volumes like I said will start in the first quarter of 2019. We did put out a press release this morning where we announced in addition to what we put out Tuesday about selling our pressure pumping business. I'll talk about more in a minute about moving 100% to West Texas Sand, so we will be decommissioning our Brady Sand mine. Going forward, I'll talk more about that in a minute, but it's all really driven by economics and the cost savings that we can generate by moving to West Texas Sand about $400,000 cost savings per well.

Looking at our divestures process, we have continued to divest those assets and say we've divested about 500 million of assets that being our return basin asset to a small package in Eagle Ford or West Panhandle in the third quarter. And then we've got one South Texas asset that we just talked about our Sinor Nest that we sold and announced in late October that we will close in early December.

Also those are bringing about $500 million. We do have the last asset in our portfolio that we announced that we're going to divest is our Eagle Ford. That process is still ongoing, but with the backdrop of what's happened with commodity prices, it may take a little longer to get that done. So it may not be done by year-end, but it's still progressing.

Capital program for the year is still at $3.4 billion. We think that’s basically funded by cash flow. We’re looking at as a cash flow neutral year. We may use a little bit of our asset divesture proceeds to fund that. But in general, it's pretty well neutral for the year.

Production profiles still expect to grow 19% to 24%, as we've talked about in the last couple of quarters, being in the upper half of that range, so we're on target to do that. And probably one of the bigger things that we've accomplished this year is really demonstrating that these horizontal wells that we're drilling, that high rate of returns that they generate are now translating into high return on capital employed. And so we'll be above 10% this year compared to where we've been running last year about 4%. So we are really seeing the benefits of having a critical mass of horizontal wells that are driving returns to the bottom line of the company.

These are a couple of initiatives that we have announced this week. I mentioned the Brady Sand mine closure. So that's been announced to our employees. We are in the process of winding down operations down there that will wind down during the first quarter of 2019, and will be transitioned to 100% of West Texas Sand. And as I mentioned, it's a savings of $400,000 per well. And it really came down to just the economics of it.

If you think about West Texas Sand, the capacity out there is growing and it expected to grow to about 30 million tons annually to be delivered out of West Texas. So it makes sense as we transitioned to that that it's one, it's easier to mine, it's closer to our basin and so that makes all the sense in the world of why we ought to move that way.

Now it's bittersweet to a certain extent. It is not only on our Brady sand mine, but we've had – these people have been with us for a long time as we've had that mine since 2012, I believe, and the pressure pumping about that same time, and so while we hate to see those people move onto other things just from an economic standpoint, it makes sense.

And we owe them a truly a debt of gratitude for the ability to execute on our Shale Play in the Permian Basin because Brady has been the backbone of Permian fracture simulations for decades. And so it will be a transition that makes sense from economics, but it’s hard on the people side of the business.

On the pressure pumping side, we have talked about that earlier this week. We announced that we're selling our pressure pumping business to ProPetro. That will be happening and closed later this year. We are getting $110 million of cash for that and 16.6 million shares of ProPetro stock. So that will close here late in the fourth quarter and transition over to ProPetro.

Some of the key benefits of doing that is clearly moving our pressure pumping business from our eight fleets that we've been running into a bigger organization. So they can take advantage of economies of scale. Their supply chain economics will be better in terms of buying for 28 fleets versus the eight fleets that we're buying for.

We think that we have a long-term arrangement with them that will strengthen, not only lower our costs from just the capital investment we're doing. We're investing today about $60 million annually in that business. We have fracture fleets that we will have to refurbish over time. And so that would be incremental to that capital. So we'll save that capital upfront, but in addition to that, we will drive down our well costs. We think we've got a preferred pricing agreement with them that will have a benefit to our well costs over time.

So we're looking forward to that as we move forward and plus there's some incremental benefits as we moved to West Texas Sand just because it's finer grain, we are pumping less core sands, we're going from pumping multiple different grades of sand. There are really two grades of sand. So we think there's efficiencies and cost benefits to our wells as we move forward by moving to West Texas Sand and moving to ProPetro pumping services business.

This slide really just shows what we've been accomplishing our reduction profile. We're still growing at the 20% CAGR. We're well on our way to our 1 million in 10 goal. As we look at it, we're seven quarters into our 40 quarter plan. So we're making good progress on that and as steady as we go.

Really looking at it from a technology standpoint. One of the things that we've invested as a company, we've got data across 6,000 plus vertical wells, we've got data now about 1,200 horizontal wells. And so as we take all that data and put it together and use artificial intelligence, use robotics, we're starting to get a pretty good idea and to confirm what we thought about all these reservoirs.

And we're putting together a lot of technology here that I'm not going to say I can explain all of it and how it all works, but we've got a strong team of people that are out there and working on it that are making a difference across our wells. And so as we move forward, you're going to see us get this uplift and we're taking advantage of them from the science that we've done out here on these wells.

And so in the Stackberry, which is one we talked about here in the third quarter. This is an area that we use that data to figure out what's the optimal way to complete these wells. And you can see from the uplift that it was beneficial in the sense of a 35% uplift compared to other single zone performance of wells in that same area.

And so what this has done is really derisk about 50,000 acres in and around this one test. We got two other tests that we're doing across the basin this year. We'll have more data to report on those in next year. But they also will derisk potentially about 50,000 acres in each one of those.

And so what this does is, it allows us to put those areas that we've derisked into the portfolio, and when we're allocating capital, it has the benefit or the potential benefit of now that we have these areas to derisk. Those can come into 2019 program and save us incremental capital potentially by putting development plans in these areas that already have infrastructure. And so rather than having a capital in our plan that is infrastructure needs. This can go in areas that we already have extra infrastructure built and therefore save us capital in 2019.

This slide is really a good depiction of – and I'll use what Joey said on our third quarter call is really the depth of 3.0+ in 3.0 Versions. As we've looked across the basin, we are – if you look here at the lower right, using 45 different completion styles. And so it's not one recipe anymore and using the generalization of Version 3.0 or Version 3.0+ is no longer really a relevant way to look at it, because this year we're using 45 different recipes out there across the basin.

And so we've come to the conclusion that we really need to think about this is a customized plan by area within the basin, and then by zone, and so each one of those has its optimal recipe. And the nice thing about the data that we have now across the basin we have a good idea of what is the best recipe for each one of those areas.

It's not to say, we won't still have some additional testing that we'll do in various these areas, but it does say that, we think we're going to be very efficient about how we complete these wells and maximize our returns, associate these wells by using the right recipe, take maximize the EURs and the returns by area. So this just shows that, probably the last time you'll see it in terms of how the 3.0+s have compared to the 3.0s and you can see it's a substantial uplift in those areas that it makes sense to do it.

Turning to marketing, marketing in our firm transportation has been a significant differentiator for Pioneer this year and will be again next year. If you look at the firm transportation that we have to the Gulf Coast, we're moving about 200,000 barrels a day of oil from January 1 to the Gulf Coast. That's up from 165,000 in the third quarter and 185,000 that will be moving here in the fourth quarter.

That oil that we moved down there is getting a Brent related price. So if you see here on the chart, you can see in the third quarter we got nearly $73 of what our sales price was for the oil out of the Permian Basin in the third quarter relative to if you were in Midland, a $55 price. So a substantial uptick that was a combination of the wide Midland differentials and then the Brent WTI differential.

So we think it's an important differentiator for us and we think that the benefit of moving all the Gulf Coast will allow us to get to a higher price market. Most of that oil's going offshore and being exported very little of it sold into the refinery market and we think long-term that will continue to be the case.

In the fourth quarter, we're anticipating about $125 million uplift from where Brent WTI differentials were at and where Midland and WTI differentials are at? So that will be there and we think that will carry over into next year.

If you look at 2019 Brent WTI differentials about $9 to $10 and Midland differentials are in that, call it probably the average $4 to $5 range, so a significant uplift that we will continue to benefit from having this FT and moving to the Gulf Coast.

This is not – we do this on oil. This slide shows on oil. We do the same thing on gas. We're doing the same thing on NGLs. So on gas – for moving gas to the Southern California market and pricing of SoCal index and just we think getting it out of basin and getting it to a higher price markets, we will improve our bottom line and our realizations and our return on capital employed associate with that. So a great thing that we've been able to accomplish, it was $189 million of incremental cash flow in the third quarter alone related to this from transportation.

On these next couple of slides really just point to how blessed as a company we are to be in the Midland Basin. And this isn't our work, but it's a – city put this work together in terms of what's the breakeven price by basin across the U.S. and you can see in the Permian Basin and Midland has a very low breakeven oil price in the high $20 range.

And so fortunately we've got the largest acreage - I've talked about there in the Midland Basin in a great position to benefit from that. And the reason it is, it's close to infrastructure. Infrastructure is built out. It's close to the Gulf Coast.

So transportation is good and you've got all these tech levels of pay, so – and it's got a high percentage of oil in the basin. So you're producing new wells, 70% to 80% oil off the bad and they'll settle out around 65% or so. So it's just a great place to have a big acreage position.

And so similarly this just points to where we are as a company and breakeven and because having basically all of our activity in the Permian Basin and being in the center cut of the Midland Basin, deepest part of the reservoir, thickest rock and multiple stack pays, we have a very low breakeven on oil price.

So lastly, here on our 1 million in 10, we're still very much committed to accomplish our 1 million in 10 plan. Like I said, we're seven quarters into that plan. We continued to focus on driving down costs, improving returns and figuring out ways to lower our cost structure and have capital discipline like the things that we've announced this week in terms of pressure pumping and sand. All those things are things that we know we need to be the low cost producer to be a long-term benefactor in this basin.

And ultimately what that will do is it not only provides a strong return on capital, but now allow in the coming months to really start focusing on returning capital to shareholders. And so those are the things that we're focused on and still too early to talk about 2019 capital budget and the team is still working on that. But it will be forthcoming in February with – we talked last week about a number of initiatives we've put those forth in the last couple of days. So hopefully that's a – you can see a good progression towards lowering our cost structure, improving returns and therefore returning capital to shareholders.

Doug, I'll stop there.

Question-and-Answer Session

Q - Douglas Leggate

Rich, thank you. I'll move over here. So folks please make yourself – if you'd like to ask a question – we got started late and you've left us plenty of time for questions. Thank you for reaching through that. Really appreciate it.

I’m actually going to kick off with a couple. I guess there's some new recent news flow between the sales to ProPetro and to the closure of the sand mine this morning. It looks like you're moving away now from the vertically integrated model. So what further steps do you have to take to be done without process?

Richard Dealy

I think these were the two main ones in terms of – from a vertical integration standpoint, the other ones are still very critical to our business in terms of water. Water is the one we get asked about a lot, and moving water around the field, having the water infrastructure that we have across the Midland Basin is strategic. We still got capital needs to be spend in terms of building out that infrastructure across the field, but also we got the Midland Water Treatment facility that needs to get completed.

And so I really don't see until those are completed that it'd be in a position that even then it may not make sense to monetize. But at least it would make – it'd be something we'd have to consider in that point in time. But until we get it built out, we think it's better inside and it provides tremendous well cost savings. And so it's something we'll have to think long and hard about whether we do something with.

I think these other ones, when you think about pressure pumping, it's really about scale as we moved towards a 1 million in 10 where we want to invest into more pressure pumping business or is it better in the hands of what would be. In ProPetro case now the largest pumping service company in the Midland Basin having a preferred customer arrangement with them having a long-term contract or we can execute sand which pure economics.

And just with the development of West Texas Sands it made tremendous sense to move there to lower our well cost and it's significant. So I think that we've got – we get asked a fair amount about midstream investments and so we had a great relationship with Targa. And the benefits of that investment have really been to allow us to talk to them in advance about what the growth rates. And 40% of the activity is going through their plants and talk to them what that growth rate looks like to make sure that we have plants built ahead of schedule to meet that demand not only on our 40%, but the other 60% of the basin.

And so that's been something that's very strategic for us and we will continue to be. I think we will always have to evaluate those things, but it's been a great relationship and allowed us to make sure that capacity is available when we need it. And we've got two more plants in 2019 and another in 2020 that are coming.

Douglas Leggate

Would you say about your rig contracting strategy going forward?

Richard Dealy

Yes. I would say our – we've used third parties. Many years ago we had a vertical drilling rig business. We sold that early in the 2013, 2012 timeframe. Going forward, I would say on our rig contract we've staggered our rig, so we have rigs that come on and ones that roll off, so we have [indiscernible] over time. A lot of those are tied to WTI oil prices and so they fluctuate with prices. So it's a good relationship in the sense of prices are higher and we're happy to share some of that margin. When prices are lower, they share it back with us. So I think we'll continue down that path for the time being.

Douglas Leggate

If I may, 1 million in 10 was pretty prescient, I think in – number of your peers have now come out with some longer-term plans and starting to talk about, the move to development more than. I think Tim and Scott before – they basically got in front of that before I think the rest of the industry did.

But having given that very long-term plan and production, you haven't or you've avoided so far giving longer-term visibility on the spending plan, and you said yourself, if you give the capital plan in February, but why not come out and give a capital plan to accompany that production plan, so the market can get – can be less surprised if you like by the step up in spending as you move through?

Richard Dealy

Yes. What we've tried to do is give guidance to it. I mean, as you know, we're always looking for ways to lower that sort of come out today and when we're got things like initiatives on sand and other things that we're working on, the goal is always to drive that down.

And I would say how we guided people is when we think about that plan in general, it takes three to five incremental rigs per year to accomplish that plan and then look at what those – the rates of those rigs would be to cost per year as a way of measuring what that looks like.

But clearly, our objective is to lower that capital cost over time. And that's investing in technology, investing in what we call rigs of the future or frac fleet to the future. One of the things with ProPetro allows on a bigger scale to really take advantage of technology.

And so all those things I think are things that we would use as a way to continue to see our capital costs come down on a per well basis. And that's really what we're trying to do. So to come out with a plan now when we got a lot of things that we're working on just seems a bit premature.

Douglas Leggate

Let me just check in the floor as you’ve got any questions. So maybe just go to the Don. Before we go to Don, I just want to – just touch on one issue you said during your presentation, because I don't know if I missed this or I heard – this is the first time I've heard it. This is the last time you're going to present the Version 3.0+, compared to the Version 3.0. So is that – are you kind of moving away from that definition of two different types of wells, because I think you said 45 different completion recipes.

And I guess what's behind my question is when you laid out the 10-year plan, the wells have gotten a lot better since you first laid that out. So there's a 10-year plan get done with fewer wells, less capital or do you end up, I hate to say it so far out coming in ahead of the 10-year plan in terms of the pacing, because a lots changed since you set the initial target, so…?

Richard Dealy

That's right. And clearly the completion technology has improved dramatically and so we've seen the well productivity increased enhancements. So today I would say that we're still working on the 10-year plan, but it takes less wells to accomplish that plan. And so I don't know that it's – yes, we're going to try and grow any faster. It's just we're going to do it more efficiently is really what we're focused on.

Douglas Leggate

Okay, but the three to five rigs still stands?

Richard Dealy

With today's technology, ultimately that would equate to getting to 70, 80 rigs in 2026, ultimately we would – much prefer to do that with 40 or 45 because the rigs were drilling the wells that much faster and we're having less downhole non-productive time, downhole equipment is more efficient. And those are the things that we see from not only artificial intelligence, but enhancements in downhole tools that will allow us to do it with a lot less rigs in the current plan today.

Douglas Leggate

Sure. Don?

Unidentified Analyst

[Question Inaudible]

Richard Dealy

Yes, I'd say like any of these transactions, there's a period of time that we’re required to hold them. And so I think clearly we'll go to that timeframe of holding them and I think we’ll have to just look at it after that point. I mean, we think that it's a great company. They will do a tremendous job for us and so we think it's a good investment.

But I think the longer-term, we'll have to look at that as whether we – at what point do we monetize those shares or reduce our shareholdings. But at this point the plan is to hold them and we'll see what the future holds. Ultimately, we hope that the pressure pumping market goes up and therefore the value we realize on this divestiture will be even higher.

Douglas Leggate

There is a question over here.

Unidentified Analyst

Yes. On the call you mentioned that you're starting a process to evaluate whether it makes sense to monetize some longer dated inventory? Can you just expand on what prompted that decision and if you can share any preliminary thoughts on what an idea level of inventory is?

Richard Dealy

Sure. Yes, I think when you have the depth of inventory that we're fortunate to have, you have to continue to look at that depth of inventory of what the timelines it's going to take to develop that. And so as we've been – this year have been focused on the other asset divestitures we have and so we're at the tail end of those divestitures.

So I think it's important that we always continue to look at our inventory that we have in the Permian Basin, assays or is their acreage in that, that is less strategic long-term or can you bring that value forward and is it more valuable in somebody else's hands than our hands.

And so we're doing that evaluation. The one thing that you want to make sure you do is you understand it, made it all these stack pays that we have in the Permian Basin as you want to have enough understanding of each of those zones before you make that decision of what that real value is and what are the economics that before we sell. We don't want to make the same mistake of other companies that have. We got that acreage that in essence sold them to us too early.

And so I think we're going through that process of like the Stackberry understanding how these other zones will work? What co-development looks like? And so we can put the appropriate priority on each one of those. And what becomes what I could have priority acreage versus secondary acreage? It's still too early for us to tell until we go through that analysis and really look at it to say what if any, we will do in 2019, but it is something that we are looking at and we'll have more to talk about over time.

Unidentified Analyst

Rich, so you've done the deal with pump, you did the sand deal. When you look out at your 2026 plan, where do you think the most work needs to be done in the near-term as far as logistics?

Richard Dealy

Great question, in terms of logistics, I think you have to – I think if I look across the basin and really think about the execution of not only what Pioneer is going to do, but what the industry is going to do in the Permian Basin? I think the tightest thing – I think infrastructure gets built.

There may be time where it's tight like it is now, but I think the midstream industry will build the pipes to takeaway oil, gas, and NGLs. I think seeing those and we're looking at the next level of commitments that will make on each of those as we speak.

But I really think as you look across the basin. My biggest fear is probably labor is really where I see the potential bottleneck. I mean there's probably 10,000 to 15,000 jobs that are in demand for labor in Midland and most of that's happening today by people coming in on rotation and coming in for two weeks and then leaving for a week.

And so you've got a proliferation of man camps in temporary housing for people and so what the basin in my mind needs, and there's a group of companies working on this with the state legislature, but also nationally is. How do we get more attention on roads, housing, education, healthcare to allow Midland, Odessa and the Permian Basin to grow in the sensitive. It can handle a higher population, but it can attract people to the basin.

I think all those things are things that as a group, as a industry that we need to focus on to bring more permanent manpower into the basin. The alternative is either you're going to have man camps like this or companies like ourselves have to do more with technology that we will do anyway.

And those things that can be done out of basin that today we do in basin do and so whether it's logistics or how we procure goods, we'll have our supply chain group of people in the basin, but some of those things with technology we can do out of Dallas, where we have a bigger labor pool and so we'll have to look at things like that as well.

So I think it's a combination of improving the infrastructure in and around the Permian Basin, but it's also using technology to do more remotely will be a combination of the results to solve them.

Douglas Leggate

Rich, one of the things that some of your – I guess peers have been talking about where we had control presenting earlier and they talked about shale model 2.0, meaning the demand from investors for growth, but with shareholder return with dividends with perhaps buyback and so on. Where do you see Pioneer on that trajectory in terms of the inflection and cash going out to shareholders?

Richard Dealy

Yes, I think we're at that inflection point. I mean if you look at the third quarter, we are basically spending within cash flow. As we move into 2019, as Tim alluded to on the call, we anticipate being shareholder cash flow positive and generating in that generated free cash flow model.

When we look at it, we take an analytical approach and try and look at a band of commodity prices that we will be in and what does our cash flow generation look like above our capital needs across the time period the next few years. And to the extent that we had incremental cash flow and to me that's cash flow that we won't need. And therefore we need to return it to shareholders.

And so we'll have more to talk about that in February, but it is something that we know we've got a strong balance sheet today and a certain amount of that cash that we won't need to perpetuate our growth profile and we can do it within cash flow.

Douglas Leggate

So you setting those parameters on a price tag or…?

Richard Dealy

I think we're, we're looking at it as a range of price outcomes just because like any commodity business we want to be protective of our balance sheet. And so to be perfected that you need to stress test that model across difference in price scenarios to the extent your – if you hedge more than you – obviously you have less volatility and it gives you more comfort in that. But I think we will stress test it and if you're go at a price level that we feel comfortable with that anything above that can be returned to shareholders.

Douglas Leggate

I have follow-up in that one. You just check in with next question over here.

Unidentified Analyst

Rich touched, just following up from Doug's question. So if we look at Pioneer’s shares outstanding about 50% from the end of 2010, one grow less and buyback stock?

Richard Dealy

We get that question a lot, it's a great question and there's no perfect answer. Everybody has a different view. We've got a deep inventory of high rate of return projects and so whatever people can differentiate and what that mix is, but it needs to be a combination of both and we think that we can accomplish it with the plan that we've laid out, have substantial growth, but that growth will generate significant cash flow that can return your money to shareholders. We can debate what the right level is. But there's a balance there.

Douglas Leggate

And that's kind of the follow-up I was going to pursue also is with the asset sales or the news this morning as well with the closure of the sand mine, the cost reduction on your capital. It would seem that your balance sheet doesn't really need a lot of help. So at what point did you build cash for a period of time? I realize you're going to tell us in February. But should we think more of buybacks being the next incremental use of cash on a more aggressive dividend?

Richard Dealy

Stay tuned. It's probably a combination where I would look at it as we go forward and we're still having discussions at the management level and at the board level on these very topics. And I can't tell you what the mix will be, but there should be – given where we're at, my belief is that we'll have extra cash flow in 2019.

We talked a year-ago about wanting to get to that free cash flow model before we had those discussions. I think we're there now, and so now I think what is the right forum for that to come back or combination of forms to return to shareholders.

Douglas Leggate

Related question, you've again reiterated today that you're comfortable with the cleanup of the portfolio, the residual that the non-core assets, if you like by the end of this year. It sounds like that is still on track, so I'm wondering if you can give us some color as to where your confidence level comes from, it sounds like you've got line of sight on exiting the rest of the Eagle Ford? But more importantly, in Q3 your cost took a bit of a step down on some fairly modest disposals. So what should we expect to happen to the cost structure as you go into 2019?

Richard Dealy

Yes, I think on the Eagle Ford thing, as I mentioned earlier, I mean it's – but for the backdrop of commodity prices, it probably gets delayed a little bit from where we were on the earnings call just because it may take a little bit longer, hopefully not. Hopefully it still gets done, but it could take a bit longer.

On the cost structure side, I mean you saw the benefit as we talked about early on, even coming into this year that as we move these divestitures out, they were higher cost assets that we moved those out, that our cost structure would be Permian only.

And so I think as you look at our Permian cost structure, you can look in our slides the margins kind of waiting the horizontal and the vertical wells and you can see where that cost structure should go post all divestitures. And then I think as you continue to see us add more and more horizontal wells to that portfolio, which have a significantly lower cost structure that you'll continue to see it way down over time.

Douglas Leggate

What is the vertical proportion of your production today? So this really come down pretty…

Richard Dealy

In fact in the 40,000 barrels a day – BOEs a day range out of our total Permian of 288.

Douglas Leggate

Right. Any other questions from the floor? We've got about five minutes left. So I just have one final one I really wanted to touch on. And of course it's a little bit predictable. It's the issue of takeaway capacity and infrastructure and so on. You guys have got very elegant solution though in terms of Gulf Coast access. How does that surety evolve with your absolute production growth? Do you maintain that full exposure to the Gulf? Or as you grow that we start to get more of a balance or are you fully committed to Gulf Coast pricing?

Richard Dealy

I think by our takeaway capacity, we're fully committed through early 2021, because our production growth profile matches what we did from transportation.

Douglas Leggate

Right.

Richard Dealy

And then in 2021, it still flat and goes out to 2025 or so. And so it's that incremental production in 2021 on our growth program that we would have another layer of pipelines that we could layer on the oil side.

Douglas Leggate

Right.

Richard Dealy

And so we'll have to decide as we get closer to that, do we layer on the next pipeline or not? And we'll just see where capacity is and what the market is at that point in time. But in general, our belief is that having those barrels states and the Gulf Coast, we'll get premium pricing to being in the Midland Basin.

And we believe that with oil and we believe it with gas, we've taken a Gulf Coast express capacity on Gulf Coast expressed to move gas out of the basin and get that to the Gulf Coast where half of that is committed to LNG and the other half is be sold the – or into the Mexican market. So we just think that the closer you can get to the ultimate users of that product, the higher price you're going to get and we think it will more than cover the cost of the transport to get there.

Douglas Leggate

I'm going to ask one more if I may. Yes, gosh, you forgive ahead of time and rather Neal’s forgotten this ahead of time. So there is a fairly sizable large private company that has made it clear that it wants to put itself up for sale at some point. I'm just curious on – they would seem to be a great fit with two companies. One is much larger than you, Exxon Mobil and the other one is yourselves. I'm just curious as to what your opinion is as to whether M&A as an acquisitive, it would be something you might consider going forward to improve efficiency?

Richard Dealy

Good question, not the first time I've got that question. I think it's something that they have very good acreage in the basin, a small piece of it, probably 15% to 20% is adjacent to our acreage that would block up nicely with ours. The rest of it is more on the sides of where we're at and farther removed.

So the acreage it's adjacent. This is clearly something that we would love to trade for, do something with, but you probably wouldn't do a transaction, particularly what's happened where we're at today for just that acreage. And so it would be we're just as a company, so blessed with the acreage position we have and we've got decades of inventory that for Pioneer, it probably just doesn't make sense where we are today. That’s not part of it that we liked, but it's probably unlikely.

End of Q&A

Douglas Leggate

Not an easy question to answer, so I appreciate your patience with it. Guys, thanks very much indeed for coming back down to Miami. Really appreciate it. Thank you.

Richard Dealy

Thank you.