先鋒自然資源 (PXD) 2016 Q4 法說會逐字稿

Welcome to Pioneer Natural Resources' fourth-quarter conference call. Joining us today will be Tim Dove, President and Chief Executive 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 5, 2017.

The Company's comments today will include forward-looking statements made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in the future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's news release on Page 2 of the slide presentation, and in Pioneer's public filings made with the Securities and Exchange Commission.

At this time, for opening remarks, I would like to turn the call over to Pioneer's 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 is going to be up first. He'll 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 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 have planned for the Eagle Ford Shale later this year. Lastly, Rich will cover the fourth-quarter financials and provide earnings guidance for the fourth quarter. After that, of course, as we always do, we will 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 year-end 2016 conference call. As Frank mentioned, this is -- 2016 was one of our really best years. This summer will be the 20th anniversary of Pioneer's creation. We can 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 are in the 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 are 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. Production for the quarter was 242,000 BOE per day, again, once again, for another quarter at the top end of our guidance range. In this case, it was a range of 237,000 to 242,000.

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 upped 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 gives you a vision of the massive underlying organic growth engine that we have in the Permian Basin.

At the same time, we are proud to say we dramatically reduced our production costs 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% drillbit reserve replacement. That's adding over 200 million BOEs last year at a drillbit 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 well and, overall, a 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 since 2009 from the program, and 2016 was another excellent year in that regard in 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 and outstanding low debt numbers, as shown on the slide with debt to book capitalization on a net basis of about 2%.

We did, as we discussed last year, add rigs to the point where 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 will show you some more results about 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 the guidance, so it gives you a feel that we are really hitting on all cylinders when we can say that.

We are 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 will be taking a substantial amount of water. It'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 are glad the export ban is lifted because it's pretty clear, as you look forward, Pioneer and the rest of the domestic industry will be significant swing producers in terms of worldwide supply. And toward that end, we are exporting two 525,000 barrel cargoes to Asia in the next couple of weeks. And so we are beginning a period in which we are seeing this export becoming an 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 are looking forward to this year's plan, this year's capital plan. And it calls for us to operate 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 will be the 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 be pumping more sand in a lot of these wells, higher fluid volumes, and we're continuing to test cluster and stage length spacing in addition to furthering our well spacing tests. And so this is important, particularly important, in scenarios where we are drilling only 7,500 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 7,500 foot laterals. This is where the larger completions could make a lot of sense going forward. We will begin with about 10 plus wells in that category of something in excess of 3.0.

We are going 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 of the new drills, 11 wells, and we are going to complete nine wells that had been drilled earlier and complete those wells this year as well. So, we are looking forward to seeing the results of that, and Ken will give you some more color on that in a moment. But the objective of the new 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 than we have done in the past.

Switching now to our West Panhandle field, our famed 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 past few months at Fain. So, we are looking forward to actually transferring this into third-party facilities to give us more consistency when it comes to processing.

The 2017 campaign is going to add significantly. Again, in terms of production, we are calling the range 15% to 18%, and that's with a 62% oil content for 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, our 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 and drive down costs, and we 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 have arrived at a $2.8 billion 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 has been discussed, an overall notional cost inflation probably in the neighborhood of 10% to 15% for the year. I believe we will 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 have been able to prove for quite a long time now. So, we believe that, overall, our costs will not on a net basis be affected by inflation on the basis of those efficiency gains.

We have a substantial amount of cash flow this year, about $2.2 billion. We will 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 books 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 at about $3.00 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 of things to report regarding a couple of smaller transactions, the first two of which are related to the former Devon properties. We've agreed to sell some acreage in both Upton and Andrews Counties for about $63 million. We are 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 -- in late January to sell over 10,000 acres in the Eagle Ford. As you might expect, we are getting strong interest in these assets and these packages, and we 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 curves cross using current prices are using $55 and $3.00 for cash flow neutrality next year, in 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 the 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 a few Jo Mill wells, a few Wolfcamp D wells, and our first well in the Clearfork, which is calculated as the shallowest of the pays and the oil shales 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 when it comes to our vertical integration. We are in the process of doing some refurbishment of some of our fleets as well as prepping 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 mainline and the subsystems for our water system in the Permian Basin, including our frac ponds. We are 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 are continuing to work on the efficiency of our existing sand mine in Brady, and that will be a 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 pond production time, near the end of the decade.

Now, going to Slide 8, we just wanted to make sure that we could reconcile for you the net differences in this year's capital from last year. So without going through too much detail here, you can see we came in below the $1.9 billion budget slightly last year. We have added two net rigs for the entire year on average, which adds about $200 million or so. We are -- our carry has now been 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 that we are going to drilling wells, and so you can see we will have incremental tank battery and saltwater disposal systems that are required. But that's how you arrive, adding a couple more areas, including the Eagle Ford, at $2.5 billion for this year in terms of D&C. Again, as I mentioned we expect that -- you notice 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 to our Company just simply because of vertical integration.

Now, let's see. Turning Slide 9, I alluded to, in my initial remarks, that we are rolling out a new vision for the next 10 years. This is something we have verbally been discussing in public forums as well as internally for some time now. But it's a view towards the next 10 years. It probably can only be afforded companies like ourselves with our inventory of drilling. The slogan is shown here in the box. It's "1,000,000 million in 10". It is the exact same slogan and vision we use with our employees. We've 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 note this is really not a change in strategy, but it's simply a reflection of what we can accomplish based on our prolific asset base, particularly in the Permian Basin. It's reflecting organic growth. That's really an important point as well. We don't really need to put capital toward land grabs 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 locations selected for the next three years of drilling in the Midland Basin. Basically it sticks on the net. So the next three years are essentially called for from the standpoint of internal planning.

\You'll notice that we said in this slide here 15% plus. Obviously, that means we are 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's always a tension of course to bring even more PV-4. 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 would 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 then 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 where the curves cross. That's on a $55 and $3 case. We are very confident about that and essentially we have been 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 reach 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 are mostly drilling very high return oil-based economic wells, and that leads to more returns based on the rate of growth.

We will continue to be a heavy hedger. It's important in a world where 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 than where the prices are today. One important aspect of this, 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 cash flow 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 of this surrounds the idea of improving our returns. I think you will see continuous improvement in the Company's return metrics by executing on the plan the way we are talking about doing it.

So, suffice it to say, it'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 our 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 are looking forward to the next 10 years in a big way.

So, my last 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 are pointing for the first year of our 10-year plan to hit 1 million barrels of BOE per day in 10 years averaging over 15% would be the objective. So, that would lead us to a conclusion in the range of 269,000 to 276,000 BOE per day. That 15% growth rate of course through time gets us to 1 million barrels on a BOE basis by 2026.

Importantly, our oil content goes up, is expected to be about 62% this year, but you can calculate how easily it could be 70% when most of the new production after all of these years of drilling is basically Spraberry/Wolfcamp wells, which generally produce slightly over 70% oil. So, that's why that number gets to where it is.

So, right now, I'm going to pass it over to Joey for his more detailed review of the Permian operations.

Thanks Tim. I'm going to be picking up on Slide 11. I'm 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 incremental costs 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'm going to move on to Slide 5 where we talk about our lower Spraberry Shale performance, which continues to track the 1 million barrel type curve. We do have some completion variations planned for 2017 focused primarily on higher proppant concentrations and modified fluid systems.

Moving to Slide 13, this is an updated format from past presentations. We are 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 than 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 costs in EURs, but I would encourage everybody to take these projected EURs in the appropriate context. Keeping in mind that our development and understanding of the lower Spraberry Shale and Wolfcamp A is far less advanced than that in the Wolfcamp B so we have a tendency to be on the conservative side. In addition to that, as Tim has already mentioned, we will be going out into five new areas, and so we are looking forward to getting more results in those areas.

There will be a slight uptick in our tank battery and saltwater disposal construction costs for 2017. For contrast, only 16% of our 2016 ops 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 $3.00 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 are looking forward to realizing the benefits of our long-term strategy for managing these dependencies considering the general industry concerns over cost inflation and capacity 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 our 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 facility similar to what we're doing in Odessa.

Now, moving on to Slide 16 and my final slide, in Q4, we popped 66 wells and averaged 188,000 BOEs per day, and ended the full year with 236 pops at an average production rate of 171,000 BOEs per day. This represents 36% growth over 2015 with oil growth at 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 oil 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 spud to pop cycle times. There are simply just times when multiple rigs get in sync with one another and it forces you, at times, to go through pop frenzies and, at other times, to go through pop droughts. And also, whenever you have a change in rig count, it adds to this complexity. For example, our lowest rig count in Q3 was in Q3 of 2016. So whenever you are 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 are looking forward to a great year in 2017 for the Permian team. And I'm 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 drilled uncompleted wells drilled about a year ago and 11 new wells where we will test design changes expected to significantly increase recovery. The design changes include over 40% longer laterals averaging about 7,500 feet, tighter cluster spacing, and much higher profit concentrations which have yielded 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'm 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 includes non-cash mark-to-market derivative losses due to the higher prices that we had end of December versus 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 $85 million, or $0.49 per diluted share.

Looking at the bottom of the slide where we show our results relative to the guidance we put out, you can see that we are on the positive side of guidance or within guidance on everything other than G&A, and that just includes some incremental 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%, NGLs 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, you know, we benefited from.

The other thing we talked about is big users 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, to $680 million for the year. So we continue to be strong users of derivatives and they benefit the Company.

Turning to Slide 20, looking at production costs, I think, if you look at it in total and back out production ad valorem taxes that are more tied to commodity prices, the production costs for the quarter were flat quarter-on-quarter. If you look at base LOE, quarter-on-quarter, it's up slightly. That's mainly due to the repairs related to the issues we've had at the West Pan field and on the Fain gas plant and a little higher activity in the Eagle Ford and Permian vertical wells.

The other piece of it is you'll see that third-party transportation costs are down. As you can imagine, the largest component of that is Eagle Ford transportation. As that production continues to decline, it becomes a smaller proportion of the overall Company. Therefore, on a BOE basis, that is continuing to decline.

Turning to Slide 21, looking at our liquidity position, the Company is in excellent condition, excellent liquidity. We've got net debt of about $200 million, a $1.5 billion undrawn credit facility, so great liquidity position.

If you look at our maturity schedule here on the chart, you'll see, 2017, we have bonds coming due. Those are in March. We plan on paying goes off with cash on hand. And then our next maturity is in May of 2018. And we also, based on today's outlook, will pay those off with cash on hand. So, excellent condition.

Flipping to Slide 22, really switching to the first-quarter guidance, production at 243,000 to 248,000 BOEs a day. And then the rest of these items are all consistent with the third quarter ore other than DD&A, which we've adjusted for the higher year-end reserves that we've had. So all of these are something you would have seen in the past. I won't go through those in detail. And with that, why don't I stop there and we will open up the call for questions.

(Operator Instructions). Pearce Hammond, Simmons.

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?

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 had taken the decision last year to take a hiatus in terms of drilling, and we agreed, just based on what was going on with economics, because we could also focus on the North. That said, we feel like that, when prices exceed roughly $50 in terms of the forecast, that they would want to come back and do some drilling. And toward that end, we've agreed to this four rig campaign.

I mentioned 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 that the zones and the economics there are essentially identical to many of the same areas in the north. So, we don't think there's any drop-off from the 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?

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's surplus, we think it's something like 300,000 to 400,000 barrels of oil per day. That said, of course there have been a few expansions that have been already announced, including Richtex 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 end in terms of how we view it in 2017 into 2018, it looks like we have sufficient takeaway to be able to be ready for Enterprise's 450,000 barrel line which is going to come on in, as currently estimated, the second quarter 2018.

The fact is there's lots of other expansions and new builds under 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 to the market is like a revolving door in terms of pipeline companies wanting 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 that 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.

Brian Singer, Goldman Sachs.

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's 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 risks such as faults or carc or whatever the case may be. And so therefore the ability to make sure we get off good completions.

The second thing is we have not yet done any drilling yet in our major units. That's because a 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 makes sense. These are areas, incidentally, when I talk about the units, that were the subject of some of our very best vertical wells for years. And we've seen a strong correlation between how the historical vertical wells tie to new horizontal production. In other words, good rock begets good rock. And so we are looking forward to some of these new areas.

On your second question, Brian, I would simply say we don't see any degradation at all in terms of the quality of this asset going forward. People talk about what we are drilling the core, the core, we are really not. We have been focused on the Wolfcamp B. But the Wolfcamp B is basically prolific over a huge swath of the acreage, some 600,000 plus acres in the core. And so we don't see really any anticipated reduction.

Now, what we would say to you is some of the zones we will 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 assess the Wolfcamp A, the Jo Mill, even at a point where we progress at the 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 a lot -- as much well control. Joey mentioned it in his comments. But I think what we're going to be doing is focusing on all of these key zones and we're 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 premature 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 of the operating metrics surrounding 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 just don't see any groundswell of activity on the board discussing anything other than that on a go-forward basis.

Great. Thank you.

Scott Hanold, RBC Capital Markets.

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 that 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 realize, when upstream companies make 50% to 100% rates of return on the wells, it has to do with the high-quality rock and the cost efficiencies that we are 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've seen from time to time. At a minimum, we've seen through the years a return to the upstream of 35%. And so I would say that, as we look forward, we will be looking towards return metrics that would be well in excess of 35% to be able to prosecute the plan efficiently.

When it comes to ROCE and ROE metrics, this is more complicated because it refers to past drilling campaigns, past results, and the effect of price on those. What I'm going to tell you is our objective is to substantially improve our ROE and ROCE numbers from where they have been. That's the goal, and that will reflect the fact that we are drilling high 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 specific, we are saying 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. It's not out of the realm of possibilities for us to increased numbers above that. If we are able to do so along the lines of the plan I outlined, then the curves do cross in 2018. That is a point where we would be spending the amount of capital essentially equivalent to our cash flow at some point next year. So, therefore, keeping the same idea in mind, 2019 becomes a 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, but there are certainly a lot of options. There are shareholder friendly options; there are acceleration options that we could consider. We are looking at that as a high-quality problem to solve, but we are not really going to make those decisions until we are at that point when we have the cash.

Understood. I appreciate the color. Thanks.

Neal Dingmann, SunTrust.

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?

I think, right now, of course, we are already outspending a cash flow number of $2.2 billion by a substantial amount. The whole objective of overspending this year, and for that matter, 2016, is to prepare us for 2018. In other words, what we've been doing is investing in high-quality, high rate of return projects that generate substantial cash flow additions with a focus then of generating a high degree of cash flow in 2018, which corresponds to a capital budget, which is prosecuting that 15% plan. That's when the curves cross.

I think we're going to stick on our plan. I think you'll see us continue with the current rig campaign through the majority of this year. We obviously, in a 10-year plan where we are adding production, we will be adding rigs through that time period. And we will be adding rigs in 2018 to that extent. Probably the 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 of this 15% to 18% growth for this year and prepping 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?

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 is simply the case that we believe there is an incremental value attached to these light sweet barrels going into international markets. And I mentioned earlier that this first quarter set of cargoes 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 toward that end, I think it will be a continuing part of our plan. But I would expect it to be ratable this year, but I think, as our production goes up and we execute this case of going to 1 million BOE per day, we need to be an exporter of 700,000 barrels a day when the time comes.

That's great to hear. Thanks Tim.

Charles Meade, Johnson Rice.

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 that 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 would be that we don't mind adding some percentage of increased growth above that. That's why we have 15% plus. We want to make sure, if we do so, we do 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.

The concern would be if we get too much in acceleration mode, you have diminishing returns. I think the industry is staring at that right now -- the truth is as more rigs come back. We are not in that situation. We've been operating through this downturn, and we are essentially continuing to operate out of it. And therefore, we are extremely efficient, we have all of our people working, and we're going to be able to mitigate a lot of 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 what 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?

Just to comment on that, Charles, maybe Joey can comment after I do. We are not completing these wells in the same zones that the vertical wells we were completed in. In fact, a lot of those wells were not deepened into the Wolfcamp back in the day. So, we have essentially pristine Wolfcamp in a lot of the areas we are talking about, so I think we're going to start there and we will 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 fact of having to spend more capital on infrastructure, we are not getting out on a limb or over our skis on what those areas are going to produce. But we are pretty excited about them because, as I mentioned, there definitely is a correlation between how well the vertical wells perform and then the subsequent horizontals. Joey, do you have any further comment?

No. We are just really commenting on that because of the additional facilities CapEx that's required, but we do have high expectations for these areas. Pioneer has one of the largest data sets 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.

Michael Hall, Heikkinen Energy Advisors.

Good morning. 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?

Let me comment about the first of those points. First of all, as you look back at the plan we prosecuted in the Eagle Ford through many years, at least for the last couple of years, we were drilling in 2014 and 2015, we were heavily choking back the wells just with the idea that would improve their EURs. And in doing so, we've masked the fact that, as we got a little bit too far downspaced, we were actually destroying value by having reduced EURs. So that dawned on us as we got into the analysis in 2016, and that's why these next tests are so critical, because we are going to, as Ken mentioned, get out to the point where these wells are more widely spaced. We're going to put bigger style fracs on these wells than we ever have in the Eagle Ford -- now others have successfully, but again more of the, to use Permian vernacular, 3.0 style completion. And therein lies the proof in the pudding. We are going to have to see what that means. If these wells perform as we suggested in our comments, that means there's 1,000 well inventory of these very high-quality, high-return wells. That changes the whole view of the asset if we can actually prove that. So we are going to be evaluating this through the year and look at these well results. And the well results will dictate where we go with Eagle Ford, including the potential to just ramp up a drilling campaign. So, we will 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?

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-yar plan to 1 million barrels a day of water. So what we're talking about in this water business is tantamount to a linchpin to our success. So the spending this year, as I mentioned, has more to do with main line -- and Joey mentioned it as well -- main line construction, frac pond construction, some substations and so on with a slight amount going into the Midland, to the Midland project. That said, as we look forward to 2018, that's when the predominance of the Midland spending comes in. Probably $100 million or so will be in 2018 attributable just to the refurbishing of their plant facilities. And with additional amount of capital going in there related to just, again, the same thing, main lines and substations, we should spend essentially the 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 of our spending is done in the 2018 time frame.

That is helpful. I appreciate the color.

Doug Leggate, Bank of America Merrill Lynch.

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?

I think the proof is in the pudding on that, Doug. I think, if we can achieve the kind of returns that Ken 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 are going to keep all the other matters out in front of us as to how we might proceed. It's 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 into that mode. So, we are simply executing the plan, and then we will decide where that leads us in terms of the 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.

Yes, and I think you're right about that. Eagle Ford in our area, as you know, is roughly a third oil, a third gas 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, we are expecting some improvement in ethane prices as the crackers continue to be built out in the Gulf Coast. You've seen a substantial amount of improvements in ethane simply because of the burgeoning export market for both it and propane. Natural gas is a bit on the come, obviously. If we can get a relatively higher gas price well into the upper $3s, the analysis changes materially because of the amount of gas in these wells. So this is something that's going to be part of the analysis. We'll have to look at what the outlook is for all three of these commodities. That's just simply not as much of a factor in Permian drilling where we drill wells, as I mentioned earlier, 75%, 80% and the first production of the wells is oil with the balance being gas and NGLs. So it's not as big of an issue in Permian, but it is an issue for Eagle Ford. We need to 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 A, when I look at the mix of wells as we approach 800 wells, only about 9% of our wells are lower Spraberry Shale, and about less than 20% are Wolfcamp A. Add to that that 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 in the Wolfcamp A. And just will looking at the Wolfcamp A curve, you can see it just took a while for that separation to take place. So, the reality is we are just really in the infancy. If I looked at production days that we have with history on Wolfcamp B and total production days that we have with Wolfcamp A, it would just dwarf it. So, as Frank has mentioned in the past, and as I know, as the work goes on here at Pioneer, we just tend to be a little conservative until we get the data. But I will just tell you, the longer that they produce, the more encouraged we are. But it's just going to take time for us to get to where we can be more definitive about a higher type curve.

And one thing that happens to be the case on Wolfcamp A is they tend to be flatter for longer simply because it takes a while to get the water off the system, where the Wolfcamp A is essentially a little bit lower pressure because of its depth than the Wolfcamp B. So all of these are factors.

I appreciate the answers guys. Thank you.

Evan Calio, Morgan Stanley.

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?

That's a great question. I think that a lot of our thinking about this topic was evolving 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 dealing with, and then thinking forward as to what type of a plan we could execute going forward that would be efficient. And we landed on the opportunity to look at this 15% growth rate, and in doing so, actually spend within cash flow 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 an essentially infinite supply of wells to drill if you think of it in a PV sense that are very high quality wells in the center of the basin. Not many people can say that. And so it's just simply a matter that our asset base can deliver those kind of results. We would never come out and talk about 10 years if we didn't think it was imminently doable. We've got a lot of people who are focused on this now. We've got 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 with going towards a disbursement model, as you called it, or some related word. 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 it's with an eye on the ball towards a long-term goal. And it has really more to do with 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 you are a long ways away from that. If you look at the campaign that we are talking about over 10 years, and in fact if you take a look at some of the modeling we've done, you would say that we are about at a point where we've drilled about 25% of our inventory at currently a minimum of 20,000 wells after 10 years. So we can keep growing.

The question in our case is only a matter of how much capital we want to put to work. This is not a question of can you accomplish it? The question is what do you want to spend on it, and in doing so, what do you want to spend to make sure you continue to be efficient? Those are our main areas of focus.

Thank you.

This is Frank. I just want to add one thing. It was touched on earlier but I think it's important, and that is that we heard last year, the year before, the industry has heard it, about strengthening the returns, not only the well returns but the corporate returns that E&P companies are putting out. And that's one of the things that sort of underlines this whole program. Tim has it on his slide about improving not only the well returns, but the corporate returns. So that's a fundamental thing that's driving this whole program as well.

And to add to that, Frank, I believe that the industry has been castigated for some time regarding this concept of destroying value. The way you destroy value is you heavily accelerate when prices are high and costs are high, only to be dealt a downturn, and then you heavily decelerate at a time when costs are low. That's exactly the opposite thing you should be doing if you're trying to create value. That's why we are making progress basically an exogenous variable in 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.

Paul Sankey, Wolfe Research.

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.

When we put out the 20,000 locations available to drill, that's already a risk number by zone, and 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 that 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 look at our internal math on this, we can easily calculate 35,000 locations. Now, some of those will depend upon pricing of course as you get into some of the other zones. But we have essentially here an unlimited supply of high-quality wells. So I don't anticipate seeing any kind of degradation over the 10-year 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 $3 through the plan period essentially is what it amounts to. (multiple speakers)

(multiple speakers) basic inflation number I guess, right?

Basic inflation you'll see this year, we're still at $55. You shouldn't see much inflation above what we are seeing today because it's obviously at a point where it's substantially lower than the peak costs in the 2010 through 2014 time frame. So we are assuming, as I said earlier, and just from hearing industry discourse, about 10% to 15% this year, which would affect us by 5%, which we are going to offset by efficiencies. But that's to get you up to the $50 to $55 case. I think, if we are in the $50 to $55 case 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?

We are baking in zero performance enhancements, which doesn't make any sense if you look at how well we have done on that, but it doesn't make sense to make those assumptions until we have those in the bag. But to give you an idea, by the 10th year of the model that we run, we wouldn't expect to be running let's just say 65 or 70 rigs. It would be our intention that, by the time we get to the 10th year, we would be running, say, 45 rigs because of those efficiencies. None of that is baked in.

Okay. Finally for me, can you just remind us why others can't replicate what you're doing? Thanks a lot.

It's 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 into the landgrab business, and we could just execute on our plan. Most people, when they look at the next three to five years, they have to put together a plan to say how they are going to create the locations to make that happen. We have the locations. We have the people. We have the wherewithal. And so it's simple for us to say this is something we can execute. It 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.

John Freeman, Raymond James.

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 question, John. I think, as you know, when we got into pressure pumping, it was at a time when prices were crazy and you couldn't get services on time back in the upturn. At that point in time, we really never wanted to be 100% vertically integrated in pressure pumping. I think that still stands today. We always talked 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 is a lever we can pull, that we can operate these fleets very efficiently. In fact, we'd put our fleets up against any in the industry in terms of their competitiveness in efficiencies. But we still have to just evaluate where we want to put capital. As we go forward, that will be the trade-off. It's sort of a buy versus rent deal when it comes to frac fleets. So we're going to get through this year. We'll make decisions then as we get to the latter part of this year what we would want to add, whether it would be internal equipment or outside parties as we get into next year. We are executing with -- we will be exiting shortly with one outside pressure pumping fleet in the Permian. Our work 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 where the $300 million is essentially the constant in a model. That's enough to provide you what you need. And there are fits to starts because we have the sand plant that's going to need to be expanded at some point. We've already told you about the water systems. At some point, when you are fully built out, then what happens to you is it's only incremental spending. So even this year, we have money going into the expansion of one of our gas plant facilities in Permian and a new plant coming on with target next year. So, incrementally, we will be adding more gas processing facilities through time. But when it comes to the water system, once it's built out, it's good. Once the sand is built out, it's good. And then we are just about making sure, as was discussed in an earlier call, that we have all of the export pipelines space and so on out of the Basin so that we are in good position to execute the 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 presenters for any additional or closing remarks.

Thanks, everybody, for participating in the call. We appreciate you being here. We will, obviously, needless to say, be out on the road in both Vail and elsewhere as the year progresses, and would be happy to cover more of this in more detail. Really appreciate everybody's involvement and participation. Thank you.

This concludes today's call. Thank you for your participation. You may now disconnect.