Pioneer Natural Resources Company (NYSE:PXD) Q4 2016 Results Earnings Conference Call February 8, 2017 10:00 AM ET
Frank Hopkins - SVP, IR
Tim Dove - President & COO
Joey Hall - EVP, Permian Operations
Ken Sheffield - EVP, South Texas operations
Rich Dealy - EVP & CFO
Pearce Hammond - Simmons & Company International
Brian Singer - Goldman Sachs
Scott Hanold - RBC Capital Markets
Neal Dingmann - SunTrust Robinson Humphrey
Charles Meade - Johnson Rice & Company
Michael Hall - Heikkinen Energy Advisors
Doug Leggate - BofA Merrill Lynch
Evan Calio - Morgan Stanley
Paul Sankey - Wolfe Research
John Freeman - Raymond James & Associates, Inc.
Welcome to Pioneer Natural Resources Fourth Quarter Conference Call.
Joining us today will be Tim Dove, President and Chief Operating Officer; Joey Hall, Executive Vice President, Permian Operations, Ken Sheffield, Executive Vice President, South Texas Operations, Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Senior Vice President, 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 05, 2017.
The company's comments today will include forward-looking statements made pursuant of 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 the future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's news release on page two 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 Senior Vice President of Investor Relations, Mr. Frank Hopkins. Please go ahead, sir.
Thanks Ebony. Good day, everyone, and thank you all for joining us again this quarter.
I am going to briefly review the agenda for today's call. Tim's going to be up first. He will provide the financial and operating highlights for the fourth quarter of 2016 and in fact all of last year. As Tim commented in our earnings press release improving capital efficiency, strong execution and maintaining a great balance sheet, allowed the company to deliver one of the best years ever in Pioneer's 20-year history. Tim will also review our plans for 2017 and outline his vision of where he expects the company to be in 10 years.
After Tim concludes his remarks, Joey will review our strong horizontal well performance in the Spraberry/Wolfcamp which is resulting from our successful completion optimization program and improving capital efficiency. He will also provide details regarding the 2017 Spraberry/Wolfcamp drilling program.
Ken will then provide a summary of the limited drilling program that we've planned for the Eagle Ford Shale later this year. Lastly Rich will cover the fourth quarter financials and provide earnings guidance for the first quarter. After that of course as we always do, we'll be glad to take your questions.
So, with that, I'll turn the call over to Tim.
Thanks Frank and welcome to everyone to our fourth quarter and yearend 2016 conference call. As Frank mentioned, 2016 was one of our really best years. This summer will be the 20th anniversary of Pioneer as a creation. We look back at 2016 as one of the best years in that 20-year history where we met virtually all of our financial and operating goals for the year.
That's despite the fact, we're in a continuing downturn in commodity prices, but today we'll focus on our fourth quarter results, our year-end reserve data that was put out yesterday as well as our review of the 2017 capital budget that we also announced yesterday. Subsequent to that, I'll provide some commentary on a new vision for Pioneer for the next 10 years that we're very excited about.
So first I'll start on Slide 3, the bullet points are self-explanatory to some extent, but we had a great fourth quarter of adjusted income of about $85 million or $0.49 per diluted share. Our production for the quarter was 242,000 BOE per day. Once again for another quarter at the top end of our guidance range, in this case it was a range of 237 to 242.
We increased production again versus the third quarter. Importantly, that was our seventh consecutive growth quarter since the downturn began and that's important because we kept advancing the company during the downturn, making us even that more ready to efficiently execute the plan as pricing improves.
The total year production averaged 234,000 BOE per day increasing oil content to about 57%. That was also at the top end of our guidance for 2016. If you remember during the year, we continually up the percentage growth number and this was at the very top end of the range as it turned out for the year. Importantly oil production was up substantially about 28,000 barrels a day versus the prior year.
Our growth continues to be focused on the Permian operations. We had a great year there in 2016 with production up 36% and oil production up 42%. It just give you the vision of the massive underlying or organic growth engine that we have in the Permian basin.
At the same time, we're proud to say we dramatically reduced our production cost per BOE almost 30% compared to the prior-year. That's because of a substantial number of cost reduction initiatives while at the same time bringing on more low-cost horizontal Spraberry/Wolfcamp wells.
As was reported in a separate press release yesterday, we had a great year in terms of reserve replacement. Over 230% drill bit reserve replacement that's adding over 200 million BOE's last year at a drill bit F&D cost of about $9.59 that's essentially the cost of adding new reserves and a proved developed F&D cost just over $9.00. That's basically the cost of placing wells on production. So, this was really an outstanding year for reserve replacement for the company as will. Overall great year in terms of new reserves and production based on strong economics.
Let me turn to Slide 4, hedging has always been a very important part of our strategy. We added about $2.6 billion of value in the form of cash and since 2009 from the program and 2016 was another excellent year in that regard and that we provided incremental cash receipts of about $680 million.
We end the year with probably one of the strongest if not the strongest balance sheet in the entire energy complex with about $3 billion of cash on hand. Outstanding low debt numbers as shown on the slide with debt-to-book capitalization a net basis of about 2%.
We did as we discussed last year add rigs to the point we exited on the number at 17 rigs at the end of the fourth quarter as we had anticipated earlier. We did place 66 wells on production in the Permian area during the fourth quarter that was the expected number. Importantly, 38 of those were Version 3.0 wells. As we said, we increased the number last year of total 3.0 completions on the basis of how successful we had been and we'll show you some more results of that later when Joey covers his slides, but the fact is Version 3.0 completion continues to outperform our Version 2.0 wells.
We've done a great job I think if you look back in terms of completion optimization, adding longer lateral lengths, enhancing well productivity, the idea being capital efficiency gains in the field and we continue to drive down costs. That's extremely important even as we look ahead.
The 2016 drilling and completion expenses actually came in slightly below budget while production was above the top range of guidance. So, it gives you a feel that we're really hitting on all cylinders when we can say that.
We're really excited about having signed in December with the City of Midland a new water contract that has us upgrading one of their water facilities and in doing so this is really a game changer for our long-term water supply in that for the next 25 plus years, we'll be taking a substantial amount of water that's effluent water from this plant, some 240,000 barrels a day, which is really going to help as we look forward to prosecuting these many years ahead of us.
We are becoming a bigger exporter. We're glad the export ban is lifted because it's pretty clear as you look forward at Pioneer and the rest of the domestic industry will be significant swing producers in terms of worldwide supply and toward that end, we're exporting two 525,000 barrel cargoes to Asia in the next couple weeks and so we're beginning a period in which we are seeing this export becoming important part of our goals going forward. So, in summary 2016 was simply an outstanding year of accomplishments both from an operational and a financial standpoint.
Turning to Slide 5, here we're looking forward to this year's plan, this year's capital plan and it calls for us to operate to 18 horizontal rigs in the basin, 14 of which will be in the northern area. We have one more that will be added here shortly to make it 14 and four rigs in the Southern Wolfcamp JV area, that'll be a focus in the northern portion of the JV area where we see similar well results as in the actual northern acreage.
The Version 3.0 completions will be the predominant way the wells are completed. It's based on the success that we've already seen in the program to date. We will be at the same time beginning to process the planning for larger completions during 2017. I don't have a number for you yet of whether that's Version 3.5 or Version 4.0, but the fact is we're going to replevin more sand and allow these wells higher fluid volumes and continue to test cluster and stage length spacing in addition to furthering our well spacing tests.
And so, this is important and particularly important in scenarios where we are drilling only 7500-foot laterals. Our preference of course is to drill 10,000-foot laterals, but there are times when the lease configuration limits us to approximately 7500-foot laterals. This is where the larger completions could make a lot of sense going forward.
We'll begin with about 10 plus wells in that category of something in excess of 3.0. We are to be growing production substantially from the Permian growth engine. Production expected to grow 30% to 34% this year as compared to last year. Again, oil production being the predominant amount of the increase.
Ken Sheffield is going to be on here in a minute to talk more about this topic, but we are planning to complete 20 wells in the Eagle Ford this year, getting back to drilling in the case where the new drills 11 wells and we're going to complete nine wells that have been drilled earlier and complete those wells this year as well. So, we're looking forward to seeing the results of that and Tim will give you some more color on that in a moment.
But the objective of the program is to test longer laterals and put higher intensity completions on these wells. The idea is to make the completions in Eagle Ford more akin to our Permian style 3.0 completions then we have done in the past.
Switching now to our West Panhandle Field, our Fain plant throughput is in the Panhandle of Texas has fallen to the point where it makes sense for us to process this gas in third-party facilities and this will have the benefit for us of eliminating some of the plant upsets we've been experiencing for the last few months at Fain.
So, we're looking forward to actually transferring this into third-party facilities give us more consistency when it comes to processing. The 2017 campaign is going to add significantly again in terms of production. We're calling the range 15% to 18% and that's with a 62% oil content per production as an average for the company, but it really is the result of drilling horizontal wells with high oil content and high returns in this year's program.
And importantly our returns are IRRs are expected to range from 50% to 100% and that's burdened with facilities costs. So, the returns are excellent based on the fact that we've been able to improve efficiencies, drive down costs and expect that to continue.
Let me turn now to Slide 6, this is a little bit more discussion regarding the capital plan for 2017. We arrived at a $2.8 million capital program, which is $2.5 billion for drilling and completions and $275 million for various vertical integration projects. I'll touch more on that in the next slide.
We are assuming overall from the standpoint of what we've been hearing in the industry as being discussed an overall notional cost inflation probably in the neighborhood of 10% to 15% for the year. I believe we'll be able to keep our inflation numbers down to more like approximately 5% but the internal plan is to make sure that those -- that cost inflation is offset by our efficiency gains, which we've been able to prove for quite a long time now. So, we believe that overall our cost will newly not a net basis be affected by inflation on the basis of those efficiency gains.
We have substantial amount of cash flow this year about $2.2 billion. We'll supplement that with cash on hand to meet the capital budget. We as I mentioned earlier have been significant hedgers, probably one of the biggest hedge book in the industry over the years and today for 2017, our derivatives are at about approximately 85% coverage for oil this year and about 55% for gas.
The oil coverage gives us protection basically below about $49 to $50 and gives us upside to $62. On the gas side, our protection is about $3 and gives us upside to about $3.50. Again, we're going to keep our debt levels very low as you might guess in 2017 with net debt to cash flow below 1.0.
We have a couple things to report regarding a couple of smaller transactions, the first two of which are related to the former Devon properties. We agreed to sell some acreage in both Upton and Andrews Counties for about $63 million. We're still in the process of evaluating offers to sell about 20,000 acres up in Martin County and we also have opened a data room here in the month of late January to sell over 10,000 acres in the Eagle Ford.
As you might expect, we're getting strong interest in these assets and these packages and will be coming out with more information as we know it, but suffice it to say, our program for 2017 is positioning us well to be able to grow and get to a point in 2018 where we can spend within cash flow. Basically, the curve is crossed using current prices or using 55 and three for cash flow neutrality next year 2018.
Turning to Slide 7, this is more details particularly on the D&C plans for this year. I won't go into this in laborious detail, but predominantly of course this spending is in the Spraberry Wolfcamp area. It also includes incidentally coming back to a few zones, We haven't done much activity in over the last few years during the downturn including some more activities on few drill mill wells a few Wolfcamp D wells and our first well in the Clearfork, which is calculated as the shallowest of the pays and will sales in the Permian Basin. So, it will be very interesting to see what the results are as those drilling campaigns are prosecuted.
If you look at the Eagle Ford shale numbers, of course that has to do with the 20 well campaign that I discussed earlier. Other capital is going into some important projects and when it comes to our vertical integration, we are in the process of doing some refurbishment at some of our fleets as well as pressing our six fleet to go back to work this summer. So, that's some of the capital in the $275 million.
We also are moving smartly ahead on building out the main line in the subsystems for our water system in the Permian basin including our frac ponds. We're just going to begin spending on the Midland plant probably late in the year. It's not that substantial for 2017. The majority of that will come in 2018.
In addition, of course we're continuing to work on the efficiency of our existing sand mine in Brady and that will be the source of some of this capital as well going forward. I think the major investment in this will be at the time we decide to expand that mine which seems to be right now in terms of on production time near the end of the decade.
Now going to Slide 8, we just want to make sure that we could reconcile for you the net differences in this year's capital from last year. So, without going into too much detail here, you can see we came in below the $1.9 billion budget slightly last year and we have added two net rigs for the entire year on average, which adds about $200 million or so.
We are curious now being completed with Sinochem in the Southern Wolfcamp JV. So, that's a capital addition this year on a net basis. We will have more widespread activity. We have five new areas of the Permian were going to be drilling wells and so you can see we'll have incremental tank battery and saltwater disposal systems that are required.
But that's how you arrive adding a couple more areas including in the Eagle Ford at $2.5 billion for this year in terms of D&C and again as I mentioned we expected -- you know we don't have any inflation in these bars and that's because we think our efficiency gains will offset -- will be net 5% inflation torque average simply because of vertical integration.
Now let's see, turning to Slide 9 I alluded to in my initial remarks that we're rolling out a new vision for the next 10 years. This is something we have verbally been discussed in public forms as well as internally for some time now. But it's a view towards the next 10 years there probably can only be afforded companies like ourselves with our inventory of drilling.
The slogan as shown here in the box it's 1.10 million. It is the exact same slogan and vision we use with our employees. We rolled this out to all of our employees and the meaning is of course to reach 1 million BOE in the next 10 years. It's important to know, this is really not a change in strategy but it's simply a reflection of what we can accomplish based on our prolific acid-base particularly in the Permian Basin and it's reflecting organic growth that's really an important point as well.
We don't really need to put capital toward landgrabs or acquisitions to accomplish this. This is simply a number that is generated by drilling wells in our world-class asset in the Permian Basin. To give you an idea about this, we already have location selected for the next three years of drilling in the Midland Basin basically it sticks on the map.
So, the next three years we're essentially call it for from the standpoint of internal planning. You'll notice that we set in this slide here 15% plus. Obviously, that means we're targeting above 15%, but we can grow faster or slower than 15% simply depending upon the amount of capital we put to work. Of course, the objective is to efficiently process our inventory at the highest returns possible.
There is always attention of course to bring even more PV4, we know that. We have various ways we can do that in the future, but the internal goal is to show consistent growth at high returns and to do so within cash flow and with a pristine balance sheet. I guess you'd say embedded in this philosophy is our desire to avoid diminishing returns by overly reacting to price signals with our rig count.
Certainly, vertical integration and technology are going to be important components of this as we move ahead. And how about the financial implications of this? Our modeling shows as I mentioned earlier in my comments that we can begin to spend within cash flow in 2018 with a curved cross that's on a $55 and $3 case.
We're very confident about that and started to working towards as a goal for quite a long time and that puts us in a position assuming that price deck were to continue to be a cash flow generator in a positive sense after 2018 and so this is an important goal from a financial standpoint that we actually reached that point where we can say we can spend within cash flow and grow at 15% plus.
Actually, our cash flow underlying the 15% production growth is growing over 20%, that's due to the fact that we're mostly drilling very high return oil-based economic wells and at least two more returns based on the rate of growth. We will continue to be heavy hedger. It's important in a world we can't control commodity prices and I mentioned already we have a significant program in place for this year, but we've done very little for 2018 that's by design.
I think if we looked at the year, we would say as we progress through the year, we have a chance we believe where prices could be higher as we approach the latter parts of the year to be able to do hedging in 2018's and then where the prices are today. One important aspect and it's needless to say is the ability to process and execute this program despite what happens with commodity prices with a very pristine balance sheet, net debt to cash flow between below 1.0 throughout the plan period.
And the real bottom line about this is to look at our ROE and ROCE improvements. Basically, all this surrounds the idea of improving our returns. I think you'll see continuous improvement in the company's return metrics by executing on the plan the way we're talking about doing.
So, suffice it to say that's a very exciting time at the company when we can really talk about the next 10 years not many companies can do that. It has to do with our great employees. It has to do with great asset base, really some of the best rock in the industry and we feel very confident that we can pull this off. So, we're looking forward to the next 10 years in a big way.
So, my slide is Slide 10. it's about our production growth forecast a little bit of detail for both the first quarter and for 2017 in total. You can see that the production forecast as I mentioned earlier is 15% to 18%. In other words, we're pointing to the first year of our 10-year plan to hit a million barrels of BOE per day in 10 years averaging over 15% would be the objective.
So, that would lead us to a conclusion of a range of 269,000 to 276,000 BOE per day. That 15% growth rate of course through time gets us to the million barrels on a BOE basis by 2026. Importantly our oil content goes up. It's expected to be about 62% this year but you can calculate out easily it could be 70% when most of the new production after all these years of drilling is basically Spraberry Wolfcamp wells, which generally produce slightly over 70% oil. So, that's why that member gets to where it is.
So right now, I am going to pass it over to Joey for his more detailed review of the Permian operations.
Thanks Tim. I am going to be picking up on Slide 11 and pleased to report on another great quarter for our Permian team to close out 2016. Continuing to see a solid uplift from our 3.0 wells which is resulting in a quick payout for the $500,000 to $1 million in committal cost associated with these larger completions.
It is important to note from the graph on the bottom that the Wolfcamp As do take a bit longer to show the same separation as the Wolfcamp Bs and this is just simply because of the lower pressure in the Wolfcamp A and the additional time it takes for these wells to clean up due to the larger water volumes.
Now I am going to move on to Slide five where we talk about our lower Spraberry shale performance, which continues to track the one million barrel type curve. We do have some completion variations planned for 2017, focused primarily on higher propane concentrations and modified fluid systems.
Moving to Slide 13, this is an updated format from past presentations, we're now including combined costs from all zones, going back to Q1 of 2015, where we had previously only reported Wolfcamp B costs. As you can see the D&C costs have trended down 25% even though we are pumping significantly larger completions then we were two years ago with as much as two times the water concentration and 35% more sand compared to Q1 of 2015.
Going on to Slide 14, you'll see the highlights of our 2017 plan where we plan to put approximately 260 gross wells online. Approximately 85% of those wells will be in the northern area with the remaining 15% in our southern joint venture. The distribution of zones we plan to develop in 2017 is very similar to 2016 between the lower Spraberry shale Wolfcamp A and Wolfcamp B and we also plan to do some appraisal in the Clearfork. Jo Mill and Wolfcamp D.
We have noted our expected well cost in EURs, but I would encourage everybody to take these projected EURs in the appropriate context keeping in mind that our development understanding of the lower Spraberry Shale and Wolfcamp A is far less advanced than that than the Wolfcamp B. So, we have a tendency to be on the conservative side.
In addition to that as Tim's already mentioned, we'll be going out into five new areas and so we're looking forward to getting more results in those areas. There will be a slight uptick in our tank battery and saltwater disposal construction cost for 2017. For contrast-only 16% of our 2016 pops needed new tank batteries while in 2017, 40% of our wells will go into new tank batteries.
I do want to point out that I expect those numbers to go back down to 2016 levels and lower in 2018 and 2019. As you can see by the last bullet this all rolls up to a very robust program with IRRs ranging from 50% to 100% at $55 oil and $3 gas.
Moving to Slide 15 you can see our plans for gas processing, water distribution and vertical integration to support our execution. I won't go over the details that Tim has already mentioned, but I will just simply say that we're looking forward to realizing the benefits of our long-term strategy for managing these dependencies, considering the general industry concerns over cost inflation incapacity in these areas as activity accelerates.
And I do want to point out that the bulk of our water system spending in 2017 is related to mainline expansions that will allow us to connect are numerous current and future water sources located throughout our acreage including the recently announced deal with the City of Midland to take non-potable water off the tail end of their wastewater treatment facilities similar to what we're doing in Odessa.
And now moving on to Slide 16 and my final slide, in Q4 we popped 66 wells an average to 188,000 BOE's per day and ended the full year with 236 pops at an average production rate of 171,000 BOE per day. This represents 36% growth over 2015 with all growth and 42%.
Looking into 2017, we are expecting an average production rate for the full year between 222,000 and 229,000 BOEs per day, resulting in a growth rate of between 30% and 34% over 2016 with all growth being between 33% and 37%.
Looking specifically at Q1, we plan to pop 45 wells, which is lower than the 66 wells we popped in Q4 and this is simply the cyclical nature of the 17 rig program with 125 to 150 days pop cycle times. There are simply just times when multiple rigs get in sync with one another and it forces you time to time to go through pop frenzies and at other times to go through pop droughts and also whenever you have a changing rig count, it adds to this complexity.
For example, our lowest rig count in Q3 was in Q3 of 2016. So, whenever you're changing rig count, it just tends to get cyclical. As an example, when I look back at 2016, we had as many as 27 pops in one month and as few as nine in another. Offset shut in due to frac operations work similar. There are times when you have a very high percentage of production shut in and other times when you have almost none.
Example here during 2016 there were months when we only had a couple thousand barrels a day shut in while there were others where we had over 20,000 barrels shut in. So, when you look at things over the full year, the law of averages works in your favor when you shrink things down to quarters and months, the law of averages doesn't work and there are going to be larger swings and pops in production.
So, with that, we're looking forward to a great year in 2017 for the Permian team and I am going to turn it over to Ken Sheffield to cover our Eagle Ford operations.
Thank you, Joey and good day everyone. Turning to Slide 17, Pioneer will resume limited drilling and completion activity in our Eagle Ford asset beginning in the second quarter. We plan to complete and place on production 20 wells during the year, including nine drill and complete wells drilled about a year ago and 11 new wells where we will test design changes expected to significantly increase the recovery.
The design changes include over 40% longer laterals, averaging about 7500 feet, tighter cluster spacing and much higher profit concentrations which would yield to strong results in both Eagle Ford and Permian operation.
The cumulative effect of the design changes are expected to yield EURs in the range of 1.3 million barrels equivalent with IRRs ranging from 40% to 50% on the new wells. Well results in the second half of 2017 will drive future plans for the asset. The program will also moderate production decline with fourth quarter 2017 production expected to be about 20% below the same period last year.
I'll now turn it over to Rich Dealy to review financial results.
Thanks Ken and good morning. I am going to start on Slide 18 where we reported a net loss attributable to common stockholders of $44 million or $0.26 per diluted share that did include noncash mark-to-market derivative losses due to the higher prices that we had into December versus the end of September of $142 million or $0.83 per diluted share.
It also included an unusual item that was similar to what we had in the third quarter of tax credits related to research and experimental expenditures on our horizontal drilling and completion innovations, that was $13 million or $0.08 per diluted share. So, adjusted for mark-to-market unusual items, we were at $85 million or $0.49 per diluted share.
Looking at the bottom of the slide, where we show our result relative to the guidance we put out, you can see that we're on the positive side of guidance or within guidance on everything other than G&A and that just includes some increment performance-based compensation that's included there. So as Tim mentioned, another strong quarter and really a great year for the company.
Turning to Slide 19, looking at price realizations, you see that all the prices for the quarter were up with oil being up 11%, NGL being up the most at 35%, really ethane and propane are our biggest two products. They were up really across the NGL complex. They were all products were up.
Gas was up 7% for the quarter. So, all those benefited from. The other thing is we talked about is big uses of derivatives. You can see that for the quarter, we had $147 million of incremental cash flow for the quarter and that brought the total as Tim mentioned 680 million for the year. So, continue to be strong use of derivatives and debt benefit the company.
Turning to slide 20, looking at production cost. I think if you look at it in total and back out production and one taxes in a more tied to commodity prices – production cost for the quarter were flat quarter-on-quarter. If you look at base LOE quarter-on-quarter its up slightly is mainly due to repair related to the issue that we had at West Pan field and on the Fain gas plant and little higher activity in the Eagle Ford and Permian vertical wells.
The other piece of it is you will see that third-party transportation cost were down, you can imagine the largest component of that is Eagle Ford transportation and that production continues to decline and becomes the smaller proportion of the overall company therefore on a BOE basis that is continuing to decline.
Turning to slide 21, looking at a liquidity position and the company is in excellent condition, excellent liquidity, the net debt is about $200 million, $1.5 billion undrawn credit facility so great liquidity position. If you look at our maturity schedule there on the chart you will see 2017, we have bond’s coming due during March we plan on paying those-off with cash on hand and the next maturity in May of 2018 and we also you know based on today’s outlook we’ll pay those off with cash on hand, so excellent condition.
Flipping to slide 22, really or switching to the first quarter guidance production at 243,000 to 248,000 BOEs a day and the rest of these items are all consistent with the third quarter or other than DD&A, which we have adjusted for the higher year-end reserves that we had. So, all these are something you would have seen in the past -- to those in details
And with that I want to stop and we’ll open up the call for your questions.
Thank you. [Operator Instructions] And we’ll take our first question from Pearce Hammond with Simmons. Please go ahead.
Good morning and thanks for taking my questions. My first question is can you elaborate more on your decision to deploy four rigs in the northern section of the JV area for next year? What are you seeing there that excites you, and how do these wells compare to your Northern Midland Basin acreage?
Yeah, Pearce of course you know we have a partner there in the form of Sinochem. They’ve been a great partner with us for many years. They have taken a decision last year to take high yields in terms of drilling and we agreed just basis what was going on with economics because we could also focus on the North.
That said we feel like it been tries and exceeded roughly to 50 in terms of the forecast that they want to come back and do some drilling and toward the end we have agreed to this four rig campaigns. I mention in my comments as you remember that most of that all of that drilling for that matter will be in the Northern part of the Southern acreage and we find it as the zones and the economics there essentially identical to many of the same areas in the North. So, we don’t think there is any drop off standpoint of economics in fact we think they are identical and we are looking forward to the program.
Great. Then my follow-up is what are your thoughts on Permian takeaway and emerging bottlenecks on that front? And what have you done to protect PXD against potential takeaway bottlenecks? And if they do materialize, at what level do you think this could move to?
Well I think if you take a look at it right now and just do the math in terms of what we believe to be the current takeaway capacity that surplus, we think it something like 300,000 to 400,000 barrels of oil per day. That said of course there have been few expansion that have been already announced including rich tax and Cactus those total about 150,000 barrels a day.
So even if Permian volumes were to grow 400,000 to 500,000 barrels a day which is probably the top 10 in terms how we view it in 2017 and in 2018. It looks like we have sufficient takeaway to be able to be ready for enterprises 450,000 barrel line which is going to come in as currently estimated second quarter 2018.
And the fact there is lots of other expansions and new bills on the consideration that total maybe another 500,000 barrels a day by 2019. So, this is something we continually work-on, we are working our door in the market view like a revolving door in terms of pipeline companies wanted to come in and work with us, in terms of moving volumes down their pipelines.
So, we are very confident that this is really not an issue in fact we will be looking forward to taking advantage of some potentially reduced rates going forward, they would allow us to be even more economic in terms of exports for example. So, we do not see an issue here, Pearce.
Thank you, Tim.
And we'll take our next question from Brian Singer with Goldman Sachs. Please go ahead.
Thank you. Good morning.
Thank you. Good morning. Tim, within the Permian, can you talk about the geographic choices you're making of where to place rigs and drill wells in 2017 versus 2016. And then also, s you think about the next decade, I guess, specifically, how does the acreage quality of the 2017 program compare, in your mind, versus 2016 and should we expect, over the next decade, that you drill the best portions of your acreage first and then work your way down?
Yes, in terms of the campaign for 2017, there has been very specific areas we have not been drilling prior to now simply because typically two reasons; one is we didn’t have seismic over the area. Seismic is needed in order to make sure that we can have some definition regarding the ability to avoid geologic risk such as faults or carc or whatever the case maybe. And so therefore the ability to make sure we get off good completions.
The second thing is we have not yet done any drilling in our major units that's because lot of land negotiations had to take place where we could consolidate all the interest and work with the parties that are our partners to make sure we have a go ahead plan that make sense.
These are areas and so definitely when I am talking about the units there were the subject to some of our very best vertical wells for years. And we have seen a strong correlation between how the historical vertical wells tied to new horizontal production, in other words good rock beget some good rock. And so we are looking forward to some of these new areas.
On your second question Brian, I will simply say, we don’t see any degradation at all in terms of quality of this asset going forward. People talked about we are drilling the core the core really not. We've been focused on the Wolfcamp B, but the Wolfcamp B is basically prolific over a huge swap of the acreage, some 600,000 plus acreage in the core.
And so, we don’t see really any anticipated reduction. Now what we would say to you is some of those zones we'll be drilling as you get out 10 years from now may include less Wolfcamp B. That's why we are doing a lot of work here to further assist the Wolfcamp B, the Jo Mill. Even at point where we progress lower Spraberry shale and also the middle Spraberry shale. And you see some of the data we put out here is actually relatively conservative in that regard because we don’t have lot as much well control as Joey mentioned in his comments.
But I think what we are going to be doing is focusing on all these key zones and we are going to have 10 years of good quality drilling. I'm pretty confident just looking at the extensive aerial extent of the acreage.
Great, thanks. That's helpful. And then my follow-up is with regards to Slide 9. You've identified a number of long-term objectives here, including production growth, leverage, free cash flow and corporate return. Can you talk about any changes you and the board are making or considering making to long-term management incentive programs?
I think at this point in time it would be pre-mature for me to discuss what would happen over many years, but I think our current incentive programs are quite positive. They basically have us aligned with the company's returns when it comes to the drilling of these wells and all the operating metrics surrounded that for annual compensation, long-term compensation. In our case is heavily focused on our returns to shareholders and that will continue to be the focus. I don’t see any ground of activity on the board discussing anything other than that on a go forward basis.
Okay, thank you.
And our next question will come from Scott Hanold with RBC Capital Markets. Please go ahead.
Thanks. Good morning, guys.
Thanks. Good morning guys. Just on that long-term outlook, Tim, in some of your conversation, you had mentioned looking at various metrics. And have you all looked at what return metrics are going to be really the focus going forward? Is there benchmarks on ROE or ROCE that you are targeting?
First of all, the metrics they are really critical to us needless to say are the metrics on drilling. And you can see this year we have very strong metrics. We are realizing when the upstream companies make 50% to 100% rate of returns in the wells, it has to do with the high-quality rock and the cost efficiencies they were generating.
But we are also the ones taking the risk on drilling the wells and completing the wells also. So, that return metric has been something we have seen from time to time. And minimum we have seen through the years a return to the upstream of 35%.
And so, I'd say there, looking forward we'll be looking towards the turn metrics that would be well in excess of 35% to be able to prosecute the plan efficiently. When it comes to our ROCE and ROE metrics this is more complicated because it refers to past drilling campaigns, past results and effective price on those.
What I am going to tell you is, where are – our objective is substantially improve our ROCE and ROC numbers from where they have been, that’s the goal and that will reflect that fact that we are drilling higher return wells. So, that’s our number one focus. We have very specific goals for hitting ROE and ROCE targets every year.
Understood. That's great color. And as a follow-up, when you look at this long-term plan, can you give us a little bit of color around some of your hierarchy of your priorities, how you rank them? Obviously, that 15% growth seems to be fundamentally where you want to be initially. But as you look at other options like dividends and stock buybacks, how do those priorities line up? And are there specific ranges you would like to see as you start getting into that free cash flow time frame?
First of all, let me just comment on what you said, which is the 15% growth rate, just to be as specific we are seeing 15% plus. So, 15 I would consider to be the bottom of the range and then we will see what we want to do as we move ahead with the plan, if not out of the range possibilities for us to increase numbers above that.
If we are able to do so, along the lines of the plan I outline, then of course do cross in 2018. That is a point where we would be spending an amount of capital essentially equivalent to our cash flow at some point next year. So therefore, keeping the same idea in mind, 2019 becomes the year where we would generate free cash flow.
It’s obviously premature for us to give you any color on exactly what we would do with excess cash flow with serving a lot of options there are shareholders friendly options, there are acceleration options that we could consider we are looking at that is a high quality problem to solve, but we are not really going to make those decision until at that point, when we have the cash.
Understood, I appreciate the color. Thanks.
And we’ll take our next question from Neal Dingmann with SunTrust. Please go ahead.
Good morning gentlemen. My question, Tim, is maybe kind of a little bit of follow-on to Scott's, and that is you guys put out a great detail as far as what you're expecting, adding the one rig, the production growth you just suggested with quite minimal outspend. Is really the focus on that, is it more about the limited outspend?
I guess I'm trying to ask another way of these are prices where you would just -- given the returns you have on these wells and your outstanding cash balance and liquidity and leverage, are there thoughts about increasing that?
Well I think right now of course we are already outspending a cash flow number of 2.2 billion by substantial amount, the whole objective of overspending this year and that for matter 2016 as prepare us for 2018. In other words, what we have been doing is investing in high quality, high rate of return projects to generate substantial cash flow additions with the focus then of generating a high degree of cash flow in 2018, which correspondence to a capital budget which is prosecuting that 15% plan, that’s when the curves cross.
I think we are going to stick on our plan. I think you will see us continue with the current rig campaign throughout the majority of this year. We obviously in a 10-year plan where we are adding production, we’ll be adding rigs to that time periods and we will be adding rigs in 2018 to that extent probably middle part of 2018 would be the current view, but that will be something we continue to assess. But suffice it to say right now we are stuck to our plan and we are moving ahead on this 15% to 18% growth for this year and preparing for 2018.
Understood. Great. I really like the growth. And then just one follow-up. Export certainly are notable now, having even two cargoes in this first quarter. Again, what are you thinking for the rest of the year to that? How much more could that grow per quarter? I don't know. I'm not going to hold you per quarter. And then just what are the differentials on that? How does that differ versus what you're just receiving here in the States?
Yeah, I think the expectation is based on our production continuing to grow. We would be exporting probably at a similar ratable quantity as we are doing here in the first quarter. It simply the case that we believe that there is an incremental value attach to this light sweet barrels going into international markets and I mentioned earlier that this first quarter set of cargos are going to Asia, we see opportunities in Europe and South America, Asia and so on to take these barrels into more transportation style, refinery complexes and through that end I think it will be continuing part of our plan, but are expected to be ratable this year, but I think as our production goes up and we execute this case of going to million BOE per day we need to be an exporter of 700,000 barrels a day when the time comes.
Well, it's great to hear. Thanks, Tim.
And our next question will come from Charles Meade with Johnson Rice. Please go ahead.
Good morning, Tim, and to the rest of your team there. You probably added some good color on this 15% CAGR floor I guess as you're characterizing it now. But if we could explore that a little bit more, is that kind of a soft governor for you that you want to be up a minimum of 15%? And then what is the higher end of that range that you would contemplate before you would maybe accelerate some of these above-ground issues on your timeline?
Sure, Charles. I think the fact is we are choosing about a 15% growth rate, because we think that's the number at which in excess of 15% we can grow very efficiently within the company. So, the concern will be that we don't mind adding some percentage increase growth above that, that's why we have 15% plus. We want to make sure if we do so we did not have diminishing returns.
In other words, we're going to maintain our process orientation with a rig count, which grows successively through time. And in doing so do it very efficiently at high returns. And the concern would be if we get too much of an acceleration mode you do have diminishing returns I think the industry steering it that right now.
The truth is as more rigs come back we're not in that situation, we've been operating through this downturn and we're essentially continuing to operate out of it. And therefore we're extremely efficient. We have all of our people working and we're going to be able to mitigate and allow this cost inflation. But you can see if you have to go out and accelerate guess what, you're going to see pretty significant inflationary costs, that's that we're trying to avoid.
Got it. That's helpful, Tim. And then if I could go back to an intriguing comment you mentioned in response to Brian's earlier question. As you go into these five new areas, and presumably some of these -- or are these some of these -- those big units, some of the incremental five areas for this year. And is there -- is there any talk or what's the thought process you have around what you might see in the Wolfcamp B, in the Spraberry, and some of these areas that have been more heavily drilled vertically?
Well, just to comment on that Charles, maybe Joey can comment after I do. We're not completing these wells in the same zones if the vertical wells are completed. And in fact, a lot of those wells were not deepen into the Wolfcamp back in the day. So, we have essentially pristine Wolfcamp in lot of the areas we're talking about. So, I think we're going to start there and we'll see some very good results. I did tell you though that we're going to be conservative in our forecasting, because we haven't drilled any wells there.
And accordingly, we are getting the effect of having to spend more capital on infrastructures we're not getting on a limp or over a skis and what those areas are looking to produce, but we're pretty excited about him because as I mentioned. Definitely there is a correlation between how well the vertical wells perform and then the subsequent horizontals. Joey, any further comment?
We're just really commenting on that because of the additional facility's CapEx is required. So, we do have high expectations for these areas. Pioneer has one of the largest datasets in the Permian Basin with over 7,000 vertical wells. So, we have a good idea of what to expect, but you never really know until you drill the well, but our expectations are high.
That's great color. Thank you, guys.
We'll take our next question from Michael Hall with Heikkinen Energy Advisors.
Good morning. Michael Hall with Heikkinen. Just I guess I wanted to talk a little bit about -- we haven't talked about Eagle Ford yet -- you guys are restarting that program. Maybe just some additional context as to how you see the Eagle Ford fitting in the portfolio longer-term, and what you would hope to achieve with the test this year.
If successful, does it set it up for a potential sale? And if so, what would be the first I guess use of capital there, first use of proceeds?
Yes, Michael let me comment about the first of those points. First of all as you look back at the plan we prosecuted in Eagle Ford through many years at least for the last couple of years we're drilling 2014, 2015, we were heavily choking back the wells just with the idea that would improve their EURs and in doing so we match the fact that as we get a little bit too far down spaced, we are actually destroying value by having reduced EURs.
So, that gone honest that as we got in the analysis 2016 and that's why these next tests are so critical, because were in is as Tim mentioned get out to the point where these wells are more widely space we are going to put latest style facts on these wells that we ever have in Eagle Ford and others have successfully.
But again, more of to use Permian Version 3.0 style completion and therein lies the proof of the pudding will have to see what that means. If these wells perform as we suggested in our comments that means is thousand well inventory of these very high quality high return wells that changes the whole view of the asset and we can actually prove that. So were really evaluating this through the year and look at these well results, in the well results will dictate you were where we go with the Eagle Ford including the potential to just ramp up a drilling campaign. So, we’ll be evaluating that as the year goes on.
Okay, so premature to think about it as a potential asset divestiture.
We are drilling wells, Michael right now.
All right. And then I guess I also wanted to hit on the water side. It sounds like, obviously, with the buildout in the main line this year, it sounded like you were alluding to some additional spend in 2018. Can you help quantify kind of how you see water infrastructure spend over the, I don't know, three-year window, and then just kind of how water consumption looks over that time?
Yeah. On the consumption front, I can tell you that today, every day we source 350,000 barrels a day of water roughly, that number is going up in our 10 year plan to 1 million barrels a day water. So over talking about this water business is tantamount to a linchpin to our success.
So, the spending this year's I mentioned has more to do with main line and Joey mentioned it as well mainline construction, frac ponds construction some substations and so on with a slight amount going into the Midland and to the Midland project that said as we look forward to 2018 that's when the predominance of the middle spending comes in probably 100 million or so be in 2018 attributable just to reap the refurbishing of their plant facilities.
And with additional amount capital going in there related to just again the same thing main lines and substations wishes been essentially identical amount in 2018 as we are in 2017 at that point we have essentially completed the system. You never really complete the system because you have frac ponds, you want to build closer to where activity is and so on but the predominance were spending is done in the 2018 timeframe.
Helpful. Appreciate the color.
And we’ll take our next question from Doug Leggate with Bank of America/Merrill Lynch. Please go ahead.
Thank you, good morning everybody. Good morning, Tim.
So, I'm wondering if I could ask a follow-up on the Eagle Ford. Clearly, the potential for an improvement, as you just laid out, is one thing, but the growth potential of the Permian relative to the Eagle Ford obviously stands out. Are you looking more about moving Eagle Ford to kind of maintenance level of production with a view to potential disposal, or is it truly going to drive capital relative to the Permian?
But I think that proofs in the pudding on that Doug. I think that if we can achieve the kind of returns that Tim mentioned, which would at a minimum compete in a lot of areas in the Permian on certain zones, it could actually have a longer life in terms of drilling. The main thing we want to do is prove up technically that we have these questions answered. That we have the puzzle effectively unlocked in terms of how to improve value there and we’re going to keep all the other matters down in front of us as to how we might proceed.
I mean, is clear Permian is a behemoth but Eagle Ford has been a great asset for us and a great growing asset for us for many years and this is a chance to get it back in to that mode. So, we’re simply executing the plan and then we will decide where that lead us in terms of next set of decisions.
I guess you called out the margins in that table you put in the slide deck. It kind of underlines the relative incremental cash margin you get from the Permian relative to Eagle Ford. That's really what was behind my question.
Yeah and I think you are right about that I mean, Eagle Ford in our area as you know is roughly a third oil -- a third gas there and a third NGLs. So, it's already a bit behind the eight-ball economics wise as it relates to -- the last two categories. That said that we're expecting some improvement in ethane prices as the crackers continue to be built out in the Gulf Coast.
Are you seeing a substantial amount of improvements in ethane simply because of the burgeoning export market for both ethane and profane? Natural gas is a bit on the curve obviously if we can get a relatively higher gas price well into the upper 3s. The analysis changed materially because the amount of gas in these wells.
So, this is something used to be part of the analysis we'll have to look at what the outlook is for all three of these commodities that just simply not as much of a factor in Permian drilling where we drilled wells as I mentioned earlier 75% or 80%. The first production of the wells is oil with the balance being gas and NGLs. So, this is not as big of an issue in Permian but is an issue for Eagle Ford, we'd continue to watch that.
My follow-up, hopefully a quick one, is so you've obviously improved or raised the type curve in the Wolfcamp B, but relative to your prior commentary, the Wolfcamp A, I think you'd said it was running about 25% in the last call better than your 1 million barrel curve. You've now come out at 1.2 million and a similar kind of situation with the joint venture area.
I wonder if you could just give some color as to where you are on the learning curve in those two areas. And what I'm thinking specifically is the mix of lateral lengths that's behind those numbers and where you think ultimately -- if you still think you are on an improving path on those type curves as well. And I'll leave it there. Thanks Tim.
The one thing that I would really stress on lower Spraberry shale and Wolfcamp B, delicate the mix of wells as we approach 800 wells, only about 9% of our wells are lower Spraberry shale and about less than 20% of Wolfcamp B. After that the most of those wells have only been drilled here recently. And then one good illustration the geology in the lower Spraberry shale is just different as is slightly different Wolfcamp B. And just looking at Wolfcamp B a curve you can see it just took a while for that separation to take place.
So, the reality is we're just really in the infancy. If I look at production days that we have with history on Wolfcamp B and total production days that we have with Wolfcamp B, it would just work. So as Frank has mentioned in the past and as I know as the work goes on here I know we just tend to be a little conservative until we get the data. But I'd just tell you the longer they produce the more encouraged we are, but it just going to take time for us to get where we can be more definitive about the higher type curve.
And one thing that happens to be the case on Wolfcamp A is they tend to be flat for long because it takes a while to get the water off the system, where the Wolfcamp A is essentially little bit lower pressure because of his depth in the Wolfcamp B, so all these are factors.
I appreciate the answer, guys. Thank you.
And we'll take our next question from Evan Calio with Morgan Stanley. Please go ahead.
Good morning guys. Thanks for taking my call. Maybe one just for me. What drove the 10-year guidance you introduced today? I know the pain was still drawing on the industries through your guide at this strip. Is there sufficient confidence in the long-term development plan?
Is there some acknowledgment of a future production plateau level and a realization for a longer-term, obviously, over a decade transition from a growth to a distribution company? Or any more meaning there as we think about that, the longer-term guide?
Evan, that's a great question. I think that lot of our thinking about this topic was revolving in 2016 when we saw the effects of going from 1.0 to 2.0 to 3.0 version wells and the types of returns we're doing with and then taking forward as to what type of plan we could execute going forward it would be efficient.
And we landed on the opportunity to look at this 15% growth rate and in doing so actually spend within cash full and/or generate positive cash flow above capital in the plan period. That's a game changer and it has to do with the fact that we have essentially infinite supply wells to drill if you think it in a PV sense.
They are very high quality wells in the center of the basin. Not many people can say that and so it's just a simply a matter that our asset base can deliver this kind of result. We would never come out and talk about 10 years we can think it was eminently doable.
We get a lot of people who are focused on this now. We get a lot of work to do to prosecute that plan, but I've got a lot of confidence in it. It doesn’t really have to do but going towards the disbursement model or as we called it or some related work. It has more to do with the fact that this is how we want to execute the process orientation of our company moving forward.
We can go faster, we can go slower, but this is what I am a ball towards a long-term goal and it has really more to do the assets than anything else.
Is there a plateau level in, as you think of it today, a full field development, or is it just too early to assess where that might be?
I think your long ways away from that. If you at the campaign that we are talking about over 10 years and in fact we take a look at some remodeling we've done. You would say that we’re about, at a point when we build about 25% of our inventory of currently a minimum 20,000 wells after 10 years.
So, we can keep growing. The question in our cases is only a matter how much capital we want put to work and this is not a question of -- can you accomplishes the question is what do you want to spend on it and in doing so what you want to spend to make sure you continue to be efficient. Those are our main areas of focus.
Okay. Thank you.
Evan this is -- I just wanted to add one thing and it was touched on earlier but I think is important and that is that we heard last year or a year before I think industries are about in strengthening the returns not only the well returns but the corporate returns -- E&P companies reporting out and that’s one of the things that sort of underlying this whole program Tim as on the slide about improving not only the well returns but the corporate returns. So, that’s the fundamental thing that drive in this all program as well.
And to add to that Frank, I believe that the industry is been castigated for some time regarding the content of destroying value with a way to destroy value is you heavily accelerate when prices are high and costs are high only be dealt the downturn and then you heavily decelerate at a time when costs are low, that's exactly the opposite thing you should be doing or trying to create value. That's why we are making price basically an exogenous variable and what we do going forward we are operating our process and price becomes a factor, but it's not the factor.
Appreciate it. Thank you.
And our next question will come from Paul Sankey with Wolfe Research. Please go ahead.
Good morning everyone. So, to the long-term target, could you talk about the risked and unrisked inventory assumptions that you are making in that? Thank you.
We put out the 20,000 locations available to drill, that's already a risk number by zone. It has to do with issues pertaining to making sure we shave down the EURs to give us some conservatism we also eliminate a certain percentage of locations and we feel like would be undrillable because of their lateral lengths or because of other issues such as surface related issues. So, the 20,000 inventory is essentially already risked.
If you at our internal math on this, we can easily calculate 35,000 locations. Now that some of those will depend upon pricing of course, as you get into some of the other zones but we have essentially here of unlimited supply of high-quality wells and so you don’t -- I don't anticipate significant degradation over the tenure plan.
Understood. Thank you. Could you just -- forgive me if you've talked about this, but what are the oil price assumptions, service cost inflation assumptions, that you're making in all this? Thanks.
The base commodity deck is 55 and three through the plan period, essentially –
Whether there be kind of basic inflation number, I guess?
Well basic inflation you will see this year. We’re still a $55 you shouldn’t see much inflation about what we are seeing today. Because you know it’s obviously the point where it's substantially lower than the peak cost in the 2010 through 2014 timeframe.
So, we’re assuming as I said earlier just from hearing industry discourse about 10% to 15% this year which would affect us by 5% which were going to offset by efficiencies but that's to get you up to the 50 to 55Ks. I think you were 50 to 55Ks through the plan period, that margins today essentially where they are today.
Yes, that's impressive. And then again, further to what you just said, what efficiency assumptions would you make on that long-term view? Are you just kind of baking in current performance or are you actually assuming you get better and better over time?
Yeah, we are making in zero performance enhancements, which doesn't make any sense, if you look at what we done on that it doesn't make sense to make those essential to have those in the bag but to give you an idea by the 10th year of the model that we run we would expect to be running let's just say 65 or 70 rigs will be our intentions about the time we get to the 10th year we would be running say 45 rigs, because those efficiencies nonetheless baked in.
Okay. Finally, for me, can you just remind us why others can't replicate what you're doing? Thanks a lot.
Yeah, Paul, it simply a fact that we point to substantial inventory meaning essentially endless inventory of very high quality, high return wells in the Midland Basin where we don't have to add more acreage, we don't have to get in the land grab business and you just executing our plan.
Most people when I look at the next three to five years they have to put together plan to say how they're going to create the locations to make that happen. We have the locations, we have the people, we have the wherewithal and so is simple for us to say this is not going to execute that won’t be simple to execute, because there’s a lot of moving parts. But I believe we have the capability of pulling it off.
Thank you very much.
And our next question will come from John Freeman with Raymond James. Please go ahead.
Good morning, guys.
When we are looking at the current plan where you're going to operate six of the seven pressure pumping fleets this year, longer-term, with the plan, once you get beyond the seven, to utilize third-party or potentially consider expanding your fleet.
Great questions I think as you know when we got into pressure pumping, it was at a time when prices are crazy and you couldn't get services on time back in the upturn. At that point in time we really never want to be a 100% vertically integrated in pressure pumping I think that still stands today. We always talk about being say two-thirds or 70% vertically integrated to protect ourselves from cost increases and basically make sure we can execute on our plan.
I see that going forward but that's an optionality for us that’s a lever we can pull that we proven that we can operate these fleets very efficiently in fact we put our fleets up against any in the industry in terms of their competitiveness inefficiencies. But we still have to just evaluate where we want to put capital as we go forward that will be trade-offs, it sort of a buy versus rent deal when it comes to frac fleets.
So, we are get through this year. We’ll make decisions then as we get through latter part of this year what we would want to add weather it would be internal equipment or outside parties as we get into the next year. We are that we are executing with -- we will be executing shortly with one outside pressure pumping fleet in Permian our work from in the Eagle Ford will also be done by outside parties.
Great. And then just my one follow-up along the same lines, when I'm thinking about the ten-year plan on the non-D&C component, is it best to think about it as it's roughly going to run around 10% of the total CapEx, or is it more likely the current kind of $300 million run rate is just sort of what you've generically assumed going forward?
We look at it John, where the $300 million is essentially constant in the model work that's enough to provide you what you need and there it's the start try because we have the sand plant is going to be expanded some point where you're ready told you about the water systems at some point when you are fully built out than what happens to you its only incremental spending. So even this year we have money going into the expansion at one of our gas plant facilities in Permian and a new plan coming on with target next year.
So incrementally we'll be adding more gas processing facilities through time but when it comes to water system once it build out its good, once the sand is built out its good. And then we’re just about making sure as was discussed in earlier call that we have all the export in the pipeline space and so on out of the basin. So, that we are in good position to execute plan.
Thanks Tim. Well done.
Ladies and gentlemen, that does conclude our question-and-answer session for today. I'd like to turn the conference back over to today’s presenter for any additional or closing remarks.
Thanks, everybody for participating in the call. We appreciate you being here. And we will obviously needless to say we are on the road in both Vail and elsewhere as the year progresses and be happy to cover more of this in more detail, really appreciative everybody’s involvement and participation. Thank you.
This concludes today's call. Thank you for your participation. You may now disconnect.
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