Aug 2, 2017
Executives
Frank Hopkins - SVP, IR Timothy Dove - President, CEO & Director Jerome Hall - EVP, Permian Operations Kenneth Sheffield - EVP, Operations/Engineering/Facilities Richard Dealy - CFO and EVP
Analysts
Douglas Leggate - Bank of America Merrill Lynch David Kistler - Piper Jaffray Companies Arun Jayaram - JPMorgan Chase & Co. Evan Calio - Morgan Stanley Ryan Todd - Deutsche Bank AG Charles Meade - Johnson Rice & Company Brian Singer - Goldman Sachs Group John Freeman - Raymond James & Associates Scott Hanold - RBC Capital Markets Neal Dingmann - SunTrust Robinson Humphrey
Operator
Welcome to Pioneer Natural Resources Second 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, Operations Engineering Facilities; 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 sites 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 August 26, 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, Investor Relations, Frank Hopkins.
Please go ahead, sir.
Frank Hopkins
Thank you, Yolanda. Good day, everyone and thanks for joining us for our second quarter call.
I'm going to briefly review the agenda that we're going to go through today. Tim's going to be up first.
He'll provide the financial and operating highlights for the second quarter of this year and our latest outlook for the remainder of 2017. After Tim concludes his remarks, Joey will review our strong horizontal well performance in Spraberry/Wolfcamp and he'll provide an update on drilling plans for the remainder of 2017 in this area.
Ken will then discuss the limited drilling program we have underway in the Eagle Ford Shale this year. And lastly, Rich will highlight our initiatives to lock in additional oil pipeline takeaway capacity to the Gulf Coast to cover our increasing Spraberry/Wolfcamp oil reduction.
He'll also summarize the second quarter financials and provide earnings guidance for the third quarter. After that, we'll, of course, as we always do each quarter, open the call up for questions that the group may have.
So with that, I'll turn the call over to Tim.
Timothy Dove
Thanks, Frank. And I hope everybody is enjoying what's left of their summer.
Our second quarter results were really quite good. We hit the top of our production range.
We lowered our production costs. We've added some very attractive hedges uphill, especially on oil for 2018.
And we're staying right on track from a capital perspective. You can see that on the first slide, where we cover our financial and operating highlights.
In particular, we had second quarter income, after you take out the effects of mark-to-market gains and unusual items, of about $38 million or $0.21 per diluted share. That was well above consensus for the quarter.
Production came in at the top end of our range, about 259,000 BOE per day. And without the POP delays I'll discuss later, we would've been substantially over the top of that guidance range.
This reflected an increase, of course, during the quarter of about 10,000 barrels a day, up 4% from last quarter. And that's our ninth consecutive year -- quarter of growth since 2014 when the downturn commenced.
Of course, second quarter growth continues to be driven by what's been really outstanding drilling results in the Spraberry/Wolfcamp horizontal program. Production increased 12,000 BOE a day or about 6% quarter-over quarter.
Internal rates of return in the play continue to be strong at 50% or 55%. We'll talk more about that in a couple of slides.
We have continued to see our production cost decline. It has a lot to do, especially when you take out taxes, when you just focus on the operating cost of the field, they were mixing in the higher percentage of Spraberry/Wolfcamp horizontal wells that averaged about $2.23 per quarter -- $2.23 per BOE for the quarter and they reduced our overall cost to about $6.19.
That's a reduction both from a year ago at $6.79 and even from the last quarter at $6.31. So that's a very positive thing we're seeing on operating cost.
We did see opportunities to hedge and I'm pleased about that, of course. We saw in -- actually slightly ahead of the OPEC meeting, an opportunity, an uptick in prices that allow us to do some hedging.
And then recently, over the past couple of weeks, in response to what's been happening on the inventory front, we added about 51,000 BOE -- barrels of oil per day. This is oil derivatives for 2018.
Those were struck at our typical three-way collar structure of 35, 45, 55. So that puts our overall portfolio average collars about 39, 49, 59.
So it gives us quite a good deal of protection for 2018 pricing. In fact, our derivatives now cover about 90% of our forecasted areas for this year and about 80% of our gas and about 50% now in terms of oil coverage for next year and about 15% for gas.
More details, of course, are in the back. But we'll look to do more hedges in 2018 as we look for attractive opportunities to do so in the next few months.
We'd like to be significantly higher than 50%. Our balance sheet and debt metrics continue to be industry leading.
Substantial amount of cash on hand. Very low debt statistics.
Turning now to Slide 4. We placed 61 wells on production, horizontal wells in the Permian Basin.
That was in line with our range of 60 to 65 for the quarter. I will talk about the weighting of those.
A lot of those were actually at the end of June. Of those wells, 9 were using the bigger fracs than our 3.0 completions and we're seeing very encouraging results so far.
Of course, these are using anywhere up to 100 barrels per foot of fluid and 5,000 pounds per foot of proppant. And we've seen significant increases of production over a 3.0 version.
So at some point, we may want to call this 4.0, but we'll see. The fact is, we're actually looking at upping the number of 3.0+ wells we complete as we finish the year.
Incidentally, when we talk about the effects of going from 3.0 to 3.0+, we're increasing both oil and gas production when we do so. Four of those wells that we completed in the quarter were in the Jo Mill.
We continue to see very good results from the Jo Mill. We have POP'd now several wells, both this quarter and prior quarters and these suggest that they'll be included in higher numbers in the future drilling because the results have been so strong.
The rest of the wells we completed were typical Version 3.0 completions which is now our default and they continue to outperform the earlier 2.0 style completions. Joey, of course, will have a lot more color on that as we get back to his slides.
In the Eagle Ford, we placed our 4 DUC wells. Those were wells that were drilled, but uncompleted.
Those were wells drilled in late 2015 and early '16 on production and they're really showing good performance. They're outperforming nearby offset wells that didn't have such intense completions by over 25%, in some cases over 25%, after 50 days or so of production.
And Ken will talk more about that on his slide. Permian exports continue to be strong and they actually will be increasing substantially through time as our oil production continues to move forward and up.
We exported 1 million barrels to Europe in the second quarter and expect to export another 1 million barrels to Europe and Asia in the third quarter. And those volumes will be increasing through time.
Going now to Slide 5. As I address Slides 5 and 6, I want you to know that one of the main messages for today is that there are no fundamental structural changes to this field, that is the Spraberry/Wolfcamp horizontal field or our business plans.
The wells continue to improve. Oil production's on target per well and we're actually benefiting from more gas and NGLs.
Our unexpected drilling and POP delays were unfortunate, but we're addressing those. So what I'd like to do is just give an update on some of these topics.
And also, at the end, we'll make some comments regarding how we're approaching 2018. We continue to operate the 18 rigs in the field.
Of course, we've been running 14 in the North and 4 in the South for some time now. The drilling program continues, as I mentioned, to be mostly focused on 3.0 completions.
Although we're testing some larger completions in May, as I mentioned earlier, increase that number. The returns for the program look very good.
We're using a range right now of 40% to 75%. Now that's based on $50 oil.
You recall that in the past, we used a $55 case and we generated 50% to 100% returns. Those returns still apply.
But what we're saying is the returns are still quite strong in the field and that's why our activity continues. I mentioned earlier the Eagle Ford.
We're now in the process of drilling and completing the total package of 11 new wells that we're drilling and the 9 wells that were DUCs from that late '15 and early '16 time period. But we didn't complete those on time, of course, because the economics really weren't very favorable to do so.
But the objective, as I mentioned many times, is to test longer laterals, put -- at wider spacing and put higher-intensity completions, somewhat more like Permian style completions on these wells. And we're hopeful we'll begin to see some results.
Actually, we'll see over the next 2 months -- 2 to 3 months, a lot of the new drills being completed and put on production. In fact, 2 of the wells are on production, but there's not enough data to see it yet.
But that's really going to be interesting to see because it will help frame our future in the Eagle Ford. We have returns in that field that are really currently expected at in that same $50 case, $53, to be about 35% to 45%.
We mentioned this in all the slides and such, but we did fall behind operationally on our completions in the Spraberry/Wolfcamp in large part due to unforeseen drilling delays. What happened is the delays were really the result of unexpected changes in pressure regimes in the field.
So what we've seen is increasing pressures in some of the shallow formations. It means we have too mud up substantially to deal with that problem.
And then we immediately then are drilling in the lower-pressure depleted zones and we were at a nice edge of this for -- really through all of 2016. But these pressures are changing -- changed in a subtle manner, such that we now find we have a higher percentage of what we kind of refer to as train wreck wells, where we have all kinds of problems with loss circulation and other issues because of this pressure change.
The easiest way to remediate this is with a drilling plan that takes us from a 3-string casing design to a 4-string casing design. So that's exactly what we've done.
We've solved this issue. We have addressed it and we've done so by changing the casing design which has proven to be very successful.
And one thing it does is it does increase the well cost substantially, about $300,000 to $400,000 per well. And this increase our time of drilling to 5 days or so.
But we're also a nickel and diming away other costs in these wells to try to get that money back, including changing out surfactants and other things to try to reduce cost and reduce days. So we're not going to stand pat with this increase.
We're going to chip away at it and reduce it. Cumulatively, though, what happens is, because we've impacted the schedule, we've also then reduced the number of POPs we're going to be completing this year by about 30.
Those are essentially moving in to 2018. That's 100% due to these drilling delays I mentioned which I believe we now have mitigated.
But you had to also factor in the delays not only result in deferral of wells you put on production, but it also loses production days for all the wells that get delayed that are going to be POP'd to the future, particularly in later next year -- in the next year. But the point is, we're now dealing with that and I think we have that squared away.
I have a later slide we'll talk about more detail on that. As you all know, we're heavily focused on maintaining efficient operations.
So although we would've had an opportunity a month or 2 ago to make the change, we decided not to. We decided not to accelerate activity to catch up with those at 30 POPs, especially in light of the current commodity price environment.
We could've added a rig or 2 or perhaps a frac fleet to accomplish this. We could've gone back to single well pads instead of 3-well pads.
All of these things would either chew up capital or they would be negatively impacting our capital efficiency. There aren't really many good high-quality rigs available.
And even if we want to do that, we think going -- doing inefficient things made no sense. So with our strategy, you have to realize also that if we were to come out and increase rig count today, for instance, with our 3-well pads, it would have basically 0 impact on this year's production.
So the decision was made that. We've chosen to basically not rev up the engine and chase the issue with additional capital and rigs, especially, as I said, with what's going on in the commodity world.
And since those 30 POPs are moving into 2018, this results in a reduction on our capital this year by about $100 million. Overall, I would say that decision is very consistent with our long term objective to grow production efficiently at high margins and high returns and therefore, improve corporate returns by maintaining a steady pace of activity which is, as you all know, a very important attribute of our longer term 10-year plan.
Now I'm going to turn to Slide 6. And on this slide we'll talk about the various topics, including the fact that we've been producing increased amounts of gas and NGLs in the Spraberry/Wolfcamp field from horizontal producing wells.
So it was proved, developed producing wells. They were on production at the end of 2016 have shown increases in gas and NGL production.
Incidentally, they're right on track with their oil production. What's happened is we determined that the increases are due to higher GORs or gas oil ratios, than what we forecasted at the end of last year, so almost a year ago that were used in the plan.
As you might guess, our engineers tend to forecast production conservatively, especially in areas where we don't have a lot of well history. And as a result, they used historical data for all those wells through the end of last year to establish a GOR average for the plan and these just proved to be too low compared to the actuals we're experiencing.
This is a positive thing when the smoke cleared, because the increased gas and NGL production, already this year, the first half of the year, has generated about $20 million of incremental revenue. And it will increase EURs on these wells.
It'll increase BOEs, total production from wells. It will lead to deposit reserve revisions and better returns for that matter.
So this is actually positive. What's important -- the most important thing to note, though, is we're continuing to meet our type curves for the oil in the Spraberry/Wolfcamp wells.
And already, 2017, new drills we drove this year are right on point and doing very well. In fact, some of it, as I said, are doing better than we expected as we get above 3.0 style completions.
For example, all the wells we've drilled this year, the oil content in those wells continue to average 70% to 80%, that's what you'd expect. That's what we've seen through time in the field.
And in fact, the cumulative oil content for of all the wells that have been drilled since 2011, horizontal wells I'm speaking of, has been about 70%. So the oil is doing very, very well.
It's just simply the fact we're increasing GOR which is expected. I've got a couple of slides to show you some history and some color on why that is an expected outcome.
So when we boil this down, oil is absolutely meeting our expectations on a per well basis and adding more gas and NGLs to the mix is a positive in terms of revenues and reserves without even affecting oil. So I think we have to look at that in that perspective.
Turning to growth rates. The growth rate changes we're incorporating into the modeling here now are 100% related to the POP deferrals.
And so they're not -- some -- actually, some of the increases in production related to GORs are offsetting the fact that we lost some POPs in the schedule. We now expect that the overall production growth rate will be closer to the bottom end of our range, about 15% to 16%, owing to slipping those POPs into 2018 and the delays in the schedule that came from that.
Accordingly, the oil growth rate is reduced, too. It's just simply moving to oil.
The oil is not gone here from the 30 POPs. It will come back when the wells are POP'd, probably, early 2018.
So it's a situation where this is nothing other than a deferral. We still expect oil content for this year to increase from last year and average about 58%.
That's reflecting some of the GOR data that we'll cover in a minute. So really, despite the operational issues and the higher GORs we've encountered, there is no change to our 10-year growth target on oil.
Oil maybe the same or higher as we get above 3.0+ style completions. It's also the fact that our gas and NGL growth will probably now be higher than our previous forecast.
In other words, we'll be higher than 1 million BOE in 10 years as a result. Let me talk a little bit about 2018 now and it has to do with a review of kind of what our plans might be.
We obviously have a very strong balance sheet. We're building a strong derivatives position as I mentioned earlier when I -- at the start of the discussion.
And we can manage through really any downturn or any price scenario and work towards living more within our cash flow and improved returns by doing so, especially as we drill these higher- return wells. So our objective will be, really, to be flexible, adaptive as we address our budget for next year.
As you know, in a $55 oil case which was the basis of that 10-year plan, our models always have shown and continue to show that 2018 would be a cash flow neutral year which is a major milestone we've been heavily focused on. And that case has, of course, adding 2 or 3 rigs.
In a band between $50 and $55, I think that level of activity continues to make sense, especially with our hedge structure is struck at about $50. However, I would say in a $45 case, our overspend will be pretty significant.
So at the very least, we would probably rethink adding those new rigs. Obviously, at $40 and below, a further slowdown might be warranted or would likely be warranted in my view.
So our message is that we're going to show these scenarios to our board over the next few months and we will be very prudent in trying to more closely match our cash flow and capital and preserve our flexibility to deal with any price scenario that we're dealt. I would say to you, in any case though, 2018 is shaping up as a very strong year for the company.
Now let's go on to Slide 7. This is a more granularity on POPs.
This is more information than anything else. Our plan assumed 260 POPs, with 150 of those occurring in the second half of the year.
So we actually did plan for some significant back-weighting in production in the first place. The graph on the slide is illustrative -- it shows the cumulative number of wells that we had planned to POP.
That's in the blue bars for the year. And then as you see in the orange bars, those are the actual POPs anticipated.
We did fall behind 11 POPs during the first half. You can see that there was between 110 POPs and 99 and that was related to those unforeseen pressure-related issues that led to drilling delays.
At first, you might think that falling short 11 POPs is not that big of a deal, it's not that significant. But when you couple that with the fact that many of the wells were POP'd later in the first half of the year than expected, the impact is really heavily magnified.
You just lose production days is the concept. And just for perspective, 29 of the 99 wells that we completed in the first half of the year occurred in June.
That's about 1/3 of -- all of the first half POPs were in June. And half of the June wells were POP'd in the last 2 months -- 2 weeks of the month, so second half of June.
As a consequence, you expect and it's true, July production looks very strong. But this is a timing thing related to when POPs are put on production.
Now we expect, because we said we're not going to choose to try to catch our tail here, we're going to do -- POP 131 wells in the second half of the year which will put us at 230 or 30 below the plan. And when you defer those and then you couple that with delays just due to pushing the POP schedule backwards, what you get is a significant loss in production days for the year.
So the idea is if you delay a POP of a flush-producing well for 30 days, what happens is it ends up being a significant hit to the annual production for the well. So with so many wells delayed, the result is then compounded.
So the oil is not gone, it's just produced later when the wells are actually POP'd. So what you can see on this graph and the lines though are production plots.
Using the same color scheme which is the plan in blue and the actual -- expected actual in sense of the future in orange. As you see, we lose about 8,000 barrels a day from the plan.
That's 100% related to the reduction in oil growth. But that oil is coming, it's just not coming this year.
Now I'll turn to Slide 8. And let me just say, the next 2 slides are really educational and we're including these more for your information about GORs.
So I'm not going to cover them in great detail. But I want to be clear about this.
This GOR matter is simply about physics. And it's a well-documented phenomenon in the Permian Basin.
And the cool thing about our data is we can show you history to that end. In particular, the first graph here on Slide 8, we show our planned horizontal and wet gas production for this year for all the wells we have in production at the end of that year.
So these are the PDP wells. They were on production by the end of last year.
And I'll refer to those PDP wells because that's how they're -- these are classified in the reserve report in that way. These are proved developed producing wells that you're in.
What we can show is how the actuals track on these wells compared to how they were forecasted in the plan. And in particular, what you can see is that the GOR increases that we've seen are higher than what we expected.
You can see that, actually, our GOR plan was higher than at the end of the year than it was for the first of the year, but it ended up -- results ended up being higher than we anticipated. So we produce more wet gas.
Wet gas, as you know, is that which refers to the production stream when it comes out of the well. So it goes -- the way gas goes directly to gas processing and separated into dry gas and NGLs.
So we just simply didn't get the GOR forecast right here, but it's a good thing as a point because all that amount above the dash line is incremental revenue. And so what -- the more important aspect of this slide is the bottom line which is the green line.
And it shows what our oil production has done compared to the plan for all those wells and they are right on the money is where expected to be. And so what we're seeing is even though gas and NGLs are above the plan, oil is on plan from all these wells and that's an important message for everybody to understand.
If you look at the -- just to reiterate, a reduction in production for this year on oil has nothing to do with GOR. It only has to do with the fact we had some delays in getting some new wells on production.
And then, also the decision not to be inefficient in trying to catch up has nothing to do with GORs. Slide 9, I like this slide a lot because it really has a history lesson embedded in it.
It shows the long term history of how the GORs behaved through time. And you can see on the left-hand graph, evidence from a large number of wells that over 40 years, the GOR increases and stabilizes.
You've seen -- this is from all the vertical drilling that we've done over those 4o years. But you hit about 4,000 cubic feet per barrel after about 10 years and then you ultimately reach an -- about 4,500 after 40 years.
So what we're saying is, this is normal. It's normal for reservoirs that are driven by solution gas to experience this kind of GOR history and the history shows it in these graphs.
What you also know is the increasing GORs on horizontal wells should be consistent with that because you're producing from the same field is what you expect. What you see on the right-hand graph then is the GORs for the horizontal wells that we have drilled over the last 5 years.
And what you can see, not surprisingly, the GOR goes up very similar to vertical. Now what we found is from a modeling standpoint, the GOR has increased somewhat faster than on vertical wells.
And we believe that may just be due to the fact that the horizontal wells, especially when they're completed properly, contact more surface area rock. And therefore, what happens when they do that, they draw down the pressures on the wells faster and then you get the gas ratio going up.
But you can see, it's not immaterial -- it's not materially different compared to vertical wells. Because actually, what you should expect is this to come just a little bit faster because of how efficiently we're completing the wells.
And that we modeled, of course, too low of a number for this in our 2017 plan which is what I've already addressed. One other factor that comes into play here is we have become heavily focused on the Wolfcamp zones.
That's deeper than the Spraberry zones. And accordingly, what happens is you tend to see higher GORs in general when you're drilling deeper wells because they have more pressure.
So it's not unusual to see higher GORs from that perspective also. The whole message here, again, is we're not seeing any significant changes in oil declines even though GORs are rising.
We have some slides back -- in the back of the pack at 24 and 25 that show individual wells or groups of wells, some of our earliest producers, 2011 to 2013, actually there's 26 wells in that mix, it shows just what you'd expect from this history which is GORs go up through time. And by the same token, in all these wells, oil continues to meet their expectations.
Every single well shows that. In fact, if you look at all those wells, the average cumulative content of oil from those wells has ranged from 72% to 80% through their lives, so this is right where we expect it to be.
So finally, again, when all the smoke clears, higher gas and NGL rates also mean higher BOE production and revenue and reserves. I'm going to turn now to Slide 10 and just talk about the impact to capital, where we mentioned we're reducing $100 million, that means we're just not chasing those last completions and/or drilling more wells to solve the problem this year.
We're reducing the capital by $100 million or so. That's reflected 100% in the drilling and completion capital for the Spraberry/Wolfcamp area, particularly net -- the total going down to $2.4 billion.
We expect that capital to be funded by the operating cash flow estimate today if you use $47.50 for the rest of the year, about $1.9 billion and substantial cash on hand. The fact is that, remember, we've also received $345 million of proceeds from mostly Permian acreage and divestitures this year.
And finally, on Slide 11, where we see the growth. As already mentioned, we expect growth to be more closer to the bottom end of our range because of these operational delays that we have suffered this year.
And really, the important point, I think, there is had we not experienced those delays and then we met our timing on POPs as a result, oil growth would've been right in that forecasted range of 24% to 28%. In addition, if you think about it, because of what I mentioned on GOR, we would actually exceed the top end of our range of 15% to 18% if we include the benefit of the increased gas and the NGL volumes we got related to the higher GORs that we experienced.
And finally, as I mentioned earlier, 2018 is shaping up as a very strong year for Pioneer. So with that, I'm going to toss it over to Joey and he can give a little more operational details on what's going on in Permian.
Jerome Hall
Thanks, Tim. I'll be picking up on Slide 12 which shows early results for 9 of our Version 3.0+ wells in the Lower Spraberry Shale and then 2 Wolfcamp B areas.
The upper left graph illustrates performance of 3 Lower Spraberry Shale wells with 3,000 pounds per foot of proppant loading. Same story in the upper right, except it's for a group of Wolfcamp B wells.
In the lower left, we're comparing the performance of 3 Wolfcamp B wells with higher water and proppant volumes at 67 barrels per foot and 2,500 pounds per foot. In all 3 instances, the new wells were outperforming offset wells with vintage 3.0 completions.
We're obviously very encouraged by these early results and we will be reporting on results of additional optimization tests over the next 2 quarters, including our 3 100 barrel per foot, 5,000 pound per foot wells which were just recently placed online. And in addition, we have successfully completed our fiber optic well stimulation and we'll be POP-ing our 3 wells that were stimulated along the full length using only sliding sleeves.
Moving on to Slide 13. Here, we're showing the latest results of our Jo Mill wells.
We POP'd 4 new wells in Q2. 3 of those wells are shown here compared to our previous 5 POPs.
The fourth well is cleaning up and the 3 new wells that we POP'd during our southern acreage and the 2 remaining POPs remaining in 2017 both will be in the northern part of our acreage. We continue to be very encouraged with the results of the Jo Mill.
Now moving on to Slide 14. Our drilling program continues to deliver strong returns.
3.0 completions remain the standard design. And as Tim mentioned, we'll consider program modifications as we evaluate the results of the 3.0+ completions.
We have increased the expected EURs in the Wolfcamp B and Wolfcamp A to 1.7 million barrels of oil equivalent and 1.3 million barrels of oil equivalent, respectively. Well cost have also ticked up slightly to account for the modifications to our casing design in some areas, but we continue to forecast robust IRRs of 40% to 75% even at a lower commodity price of $50 oil and $3 gas.
So wrapping up my Permian update on Slide 15. We finished the quarter with the expected 61 POPs and averaging 213,000 barrels of oil equivalent per day which is 12,000 barrels of oil equivalent per day or 6% over Q1.
The range of expected 2017 production growth has been revised to 30% to 32%. As Tim already mentioned, we're updating our full year POP forecast approximately 230 wells, with 55 to 60 of those wells in Q3.
So with that, I'll turn it over to Ken Sheffield to talk about South Texas.
Kenneth Sheffield
Thank you, Joey and good morning, everyone. Turning to Slide 16.
Pioneer resumed limited drilling and completion activity in our Eagle Ford asset in March. We plan to complete and POP 20 wells during the year, including 9 DUCs drilled more than a year ago and 11 new wells, where drilling operations were recently concluded.
Design changes for the 2017 program include increased well spacing and longer laterals for the 11 new wells and tighter cluster spacing and much higher proppant concentrations for both the new wells and the DUCs. The cumulative effect of the design changes are expected to yield EURs averaging 1.3 million barrels equivalent, with IRRs ranging from 35% to 45% on the new wells.
Four DUCs POP'd in the second quarter have been on production for about 50 days and are exhibiting greater than 20% improvement compared to offset wells with less intense completions. Two new wells were POP'd in the last few days of July and we look forward to seeing results for these 2 new wells in the balance of the program in the second half of the year.
The program will also moderate production decline with fourth quarter 2017 production expected to be about 20% below that of fourth quarter 2016. I'll now turn it over to Rich Dealy to review marketing highlights and financial results.
Richard Dealy
Thanks, Ken. I'm going to start on Slide 17, where Frank talked about giving us an update on our takeaway capacity for oil.
As you can see from this slide, we're currently transporting about 40% or 60,000 barrels per day of our own production to the Gulf Coast. Those volumes were being delivered to Corpus Christi, Houston and Nederland, 3 of the major refinery and export markets on the Gulf Coast.
Of those barrels, we're exporting about 1 million barrels per quarter, as Tim talked about, with the rest being sold in the refinery market. Longer term, we're targeting to move 70% to 80% of our planned oil production to the Gulf Coast market, where we have access to both storage and export facilities.
Over the next few months, we plan to finalize a number of agreements that will allow us to ramp up those transport volumes in connection with our forecasted oil growth plans. Once those agreements are complete, I would expect to see our export volumes grow considerably above the 1 million barrels per quarter that we're doing today.
On the gas takeaway front, just to give you an update there. We have plenty of capacity through 2019.
With that in mind, though, we're currently looking at a number of the new proposed newbuild pipelines that would come online in 2019 so that we can transport our gas, forecasted out in 2019 and beyond, to industrial users on the Gulf Coast, LNG facilities as well as export opportunities to Mexico. So we're working diligently on that.
On the NGL front, we do have adequate takeaway capacity through 2020, as well as in fractionation capacities, so we're in good shape there. And in terms of gas processing, just to give you an update there, we're working with our partners to make sure we have adequate processing capacity, in particular, target plans to start up the next new plant in the first quarter of 2018, with another plant expected in the third quarter of 2018.
Thereafter, we typically expect to see a new plant every 12 months or so and somewhat dependent on what the size of those new plants are in the future. So I think suffice it to say that you can see that we're making good progress on having ample takeaway capacity and processing to accommodate our long term growth plan over the next 5 to 10 years.
Turning to Slide 18 and earnings update. We did report net income attributable to common stockholders of $233 million or $1.36 per diluted share.
That did include noncash mark-to-market derivative gains of $71 million or $0.42, that's really due to lower commodity prices at the end of June as compared to the end of March. We did have one unusual item for the quarter.
It was a gain on the sale of our Martin County acreage that we've announced back in April. That was $124 million after tax or $0.73.
So adjusting for those 2 items, as Tim mentioned, we're at $38 million of adjusted income or $0.21 per share. Looking at the bottom of the slide where we reflect guidance relative to results.
You'll see there that what was in the guidance are on the positive side of guidance on all items. So overall, we had a very strong quarter financially.
Looking at Slide 19, you'll see that, as all of you are aware, commodity prices were down during the quarter. So we were down on realized prices 8% on oil to $45.
We're down 13% on NGLs and 6% on gas. These price realizations do exclude our derivative benefits, so we did receive $24 million during the quarter for cash receipts from our hedging activity.
You can see the impact of those at the bottom of the slide, the most meaningful being on oil, where we added about $1.59 per barrel from our hedging results. Turning to Slide 20.
Looking at production costs. Production costs in total were flat, relatively flat quarter-on quarter when you look at those bars there.
If you exclude production and ad valorem taxes, production cost were down 2% relative to the first quarter and down 9% relative to 2016. So we continue to make good progress on our production cost.
The decline, as Tim mentioned, is primarily due to our increasing production from our lower-cost horizontal Wolfcamp wells and in the company's and the operations team's cost reduction efforts. Turning to Slide 21.
We continue to have an excellent balance sheet and great liquidity. As you can see with $300 million of net debt, this does reflect the $2.4 billion of cash that we have on the balance sheet.
We have unsecured credit facility of $1.5 billion that was completely unused. That resulted in a net debt-to-book capitalization at the end of the quarter of 3%.
So overall, great financial position. If you look at our maturity schedule there, we do show our next bond maturity is in May of 2018, with the current plan to pay that off in May of next year with a cash on hand.
You will notice if you look at the balance sheet that has been moved up to current based on that plan to pay that off next year. Turning to Slide 22, looking at our guidance for the third quarter.
Daily production guidance of 274,000 to 279,000 BOEs per day. The rest of these items are all consistent with prior quarters.
I won't go through those is detail except for 2 items. DD&A, we did lower that guidance range, really, to reflect the addition of proved reserves from our successful drilling program.
And then interest expense is down, reflecting the bonds we paid off in March of this year. And you'll see the next step-down in interest expense next year when we pay off the May of '18 bonds that come due.
So with that, Yolanda, I think we'll open up the call for questions.
Operator
[Operator Instructions]. We'll take our first question from Doug Leggate with Bank of America.
Douglas Leggate
Tim, I wonder if I could just ask you a little bit more about this oil pressure issue? Is this a localized issue?
Is it across the entire play? And what makes you comfortable that this won't recur, particularly if you continue with increasingly larger frac load as you go forward?
Timothy Dove
Well, first of all, the fact is we think the recurrence of this has been stymied by the fact we're using this 4-well casing -- 4-string casing design on the wells. I mean, what we were, of course, experiencing is trying to use 3-string casing was a noble effort, but when you have subtle worsening of the pressure issue, then basically, we find ourselves having too many high-cost wells and delays as a result.
So we took the remedial action of putting the 4-string casing design in play -- in place. And it in and of itself has solved the most material parts of any issue we're going to have going forward.
Now it comes with days and it comes with a little bit more cost, but I think that solution's in place. One way we will be able to help solve our own issues are related to the fact that we're going to be utilizing a lot of our own produced water in drilling and so on.
But in terms of where this occurs, there's various over- and under-pressure situations across the basin. In particular, where we're focus, we see it more in areas of Martin County and Midland County.
Not every area, it just depends on where you are in the counties. And we typically don't see it as much where you don't have as many vertical wells drilled, in particular, the area -- what we call the SWAT or the Southern Wolfcamp JV area, we don't see this as much.
So it happens principally though in the areas where we're doing quite a bit of drilling. And so since we're a concentrated driller over adjacent leasehold, that's definitely one of the issues that we have then forced ourselves into is basically going to 4-string casing.
Douglas Leggate
Okay. So you would characterize the issue as solved now?
Or is there a risk of this becomes an ongoing issue, as I say, as you continue to test bigger plays.
Timothy Dove
This one's solved.
Douglas Leggate
Okay. My follow-up, if I may, is really on the '18 commentary around guidance.
I guess, you haven't really given guidance. But when you see the POPs moving to '18, is that additive to the '18 plan?
I guess there's a couple of parts to this question, so that's kind of part 1. And part 2 would be, well, if your type curve is so much better -- I mean, when I spoke to Frank last night, he said it's a little better.
It looks like they're exponentially better. So at what point do you look at the activity level relative to the higher well results especially it now becomes a standard well?
And what then would that do to the activity level and the production outlook for '18? I'm just trying to figure out if we've lost this production from those 30 POPs or if we get it back in '18?
And I'll leave it there.
Timothy Dove
Yes, the question is how many total POPs we're going to complete next year, right, because it depends on how many wells we're going to run, how many frac fleets. Those have not been determined.
I think it would be probably a minimum or the same type of number we planned on this year, 250 to 260. What you count in those is -- you have to decide, are you counting to 30 in those or you're going to take 30 off the back, you're going to build it to 270, 280.
Those are still all on the planning phases right now. The way I would think about '18 guidance is though that we certainly will reflect an increase in what we expect from the wells to the extent of these 3.0+ wells continue to show good results.
That's exactly what we did. If you remember, in relation to moving from 2016 to 2017, we all of a sudden were using 3.0 style completions as the ticket to our planning in 2017 and that's proving to be accurate.
So I think the real question is when do we have enough data on 3.0+ wells to make that statement. I mentioned in my comments that we're looking at potentially increasing the number of 3.0+ wells that we actually complete this year to try to get our arms around that problem.
The early returns look very encouraging. And that would lead you to conclude if you can do more or less.
In other words, we can produce that was much more oil and drill that many fewer wells that we're doing that well on a per well basis. But it gives us a lot of flexibility.
The curves are pointing up into the right in terms of well results.
Douglas Leggate
So you see '18 would be a very strong year? What are you trying to guide us to?
Timothy Dove
I'm trying to guide you to say it's going to be a strong year.
Operator
And our next question will come from Dave Kistler with Simmons Piper Jaffray.
David Kistler
Following up on Doug's question here, when we talk about catch up, it sounds like how you're answering that is really productivity of wells lead to the catch-up versus kind of the compound impact of the POP timing delays. It's not going to be catch-up driven by more spending, higher cost and, eventually, production catching up.
I'm just trying to get clarification here.
Timothy Dove
Yes, I think if you realize -- I think everybody gets fixated in moving 30 POPs. That's really not the effect, is that significant in 2017.
The bigger issue is delayed production of new wells. In other words, days on production because of moving the schedule back.
I commented on that when I was speaking in my sort of prepared notes. But -- so it's really not -- the 30 POPs swing here is not in and of itself that significant, it's basically keeping on the POP schedule and producing the wells at a certain number of production days is what are your keys to meeting your target.
I think more spending would come maybe more in the form of adding rigs, maybe adding rigs a month or 2 earlier or what have you, to help provide for a little bit more flexibility in the schedule. When you run a factory like we're, it's a pretty tight schedule.
And if you have some drilling delays like we experienced and we had to go deal with them, then there's a need to sort of stop down the factory for a while and retool it and get back running. That's what we did with the 4-string casing.
David Kistler
Okay, I appreciate that. And maybe diving a little deeper.
Obviously, stock's under pressure today. But when we think about the relative decline today versus what the relative decline might be in cash flows while you're trying to catch up, it seems like it's disproportionate to the stock performance.
Can you kind of comment on what this means in terms of cash flow outlook? Obviously, we can't control exactly where commodity price goes and whatnot.
But in a steady-state environment, is it fair to say that slippage in cash flow and production growth really isn't commensurate with what we're seeing in terms of stock performance?
Timothy Dove
I won't comment on the stock. I mean, it is what it is.
But I comment on our internal goals which would have us -- you have -- is deferring some of these production and that's not a bad thing. It should -- it might be about a good thing if prices are higher by the time the wells come back on production.
But that all said, I think the whole objective here is to get into a scenario which is still in our plan for 2018 if you were to have $55 case being basically such strong cash flow or meeting our capital needs on a neutral basis. That's still in the plan.
Operator
Our next question will come from Arun Jayaram with JPMorgan.
Arun Jayaram
Tim, my first question is just thinking about the vertical development and your kind of core area in the Midland Basin. So my question is in areas where you're seeing more dense vertical development, are you seeing any negative variances in terms of the oil decline?
Timothy Dove
No.
Arun Jayaram
Okay. So you don't think that this increase in the GOR has to do with just the historical vertical development which has been relatively dense and where your core areas is?
I just want to clarify that.
Timothy Dove
Let me reiterate it, A.J. The deal is, here, even though the GOR goes up, it does not affect the oil curve.
The oil curve is right on target. What you're doing is you're increasing more gas and more NGLs.
That's the end of story.
Arun Jayaram
Great, great. I did want to clarify that.
My second question, as you do to move to a 4-string casing design, what does this do in terms of cycle times on the drilling side and spud-to-POP ratios as you get this issue resolved?
Timothy Dove
So, first of all, if you just look at the drilling, as I mentioned, it's about 3 to 5 days incremental time to set the additional string casing. And there's a certain -- relatively limited amount of cost associated with that.
What that allows you to do is basically stay more on scheduled so that you can actually reduce your spud-to-POP timing. So what happens, of course, is if you have a relatively tight schedule which we try to run the factory efficiently and you have POPs that are delayed because of this issue, in other words, if the drilling is delayed a few days more than you thought, then what happens is the POPs are delayed and they also can get out of SKU because now you've got to move frac fleets at different locations.
It just changes the cadence of the completions. And so what we'll do here by running a 4-string casing will be much more predictable about how long the wells are going to take.
You realize, if you're in a situation where you have a low-circulation zone or a big drilling problem, like we've been having if we were running 3-string casing, we could have 20 extra days on the wells as we go try to remediate the problem. Now we're saying, okay, we're going to stick on 3 to 5 days and we can be a lot tighter on the planning.
Operator
Our next question will come from Evan Calio with Morgan Stanley.
Evan Calio
Let me just follow-up on that pressure issue. I mean, is there any color of what caused the changing pressure regimes in these shallower zones that led to the 4-string design change?
I know you mentioned that it's new, but did you expect this to change or worsen than over time? And any color there?
Timothy Dove
Well, I think most of the cause of the pressure is, particularly high pressure issues, are in the shallow zones. These are typically zones where we're reinjecting produced water.
And so to the extent we have a lot of operations going on or others do in the area, the pressure goes up in these zones. And in turns out they do naturally abate, the pressures naturally abate, so we can kind of -- in the future kind of control this pressure issue.
But ultimately, what's happened to decades of introduction of produced water into these zones, they are higher pressure by definition, so they have to be dealt with. But right now, as I said, the 3-string -- 4-string casing design solves it basically because we just sort of wire around the problem.
Now there's the other things we can do, I think which is, as I said, we can reduce ejection in certain areas around where we're going to be drilling. But more importantly, you realize there's a real opportunity at the end of the tunnel here to basically start using produced water in fracs which we're doing more and more and more as opposed to using fresh water.
So we're focusing on it now, is using produced water and brackish water and other non-potable water sources and that helps to solve the problem, too. So we have various different angles that we can approach this and avoid the issue.
But the most -- the fastest remediation, just from an operational standpoint, was to get out there and put a 4-string casing design to work, is what we've done.
Evan Calio
Great. In the second question, on the 3.0 completions, the 3.0+ completions look encouraging.
Any color you have of what are the infrastructure in place in '18 to handle a full year 3.0+ completions that require additional built-out? Or maybe just color when you'd be in the position if that were to become your base completion or the discussion of limiting factors?
I'll leave it there.
Timothy Dove
Sure. So as you know, this year, we're spending quite a bit of money on our capital water-related projects.
And I think it's also true that we'll do the same next year. This year, I think we're spending $160 million on our water projects.
Sort of early penciling in at $150 million a year for next year. The idea this year, in particular, was to build the mainline construction up from the south to the north to connect the entire field.
That's a huge game changer to be able to swing water. In addition to which, we're adding more subsystems and more frac ponds and so on as we build out the system.
The answer is yes. I mean, we're factoring in the possibility that we would go 3.0+ which is we've got to get a better name than that, I realize.
But 3.0+, we got to change -- if we change to that in a considerable fashion, you've got to up the water ante. But I think we can do that, no problem.
Operator
Our next question will come from Ryan Todd with Deutsche Bank.
Ryan Todd
Maybe to start out, one follow-up question on the GORs. I mean, it seems like -- I guess the asymptote that you're -- that it looks like you'll be approaching in terms of the long term GOR of the wells, is it the same as you thought it was and you're just getting more gas faster because of a slightly quicker pressure depletion over the life of the well?
Is the eventual pressure depletion over the life of the well consistent with what you thought it would be? And then maybe I guess from a longer term point of view, is the extra gas -- will this require any extra gas processing capacity or drive any surface constraints over the -- kind of the medium term part of your plan?
Timothy Dove
That's a great question. So I think if you look at the graph that was on Slide 9, the one in particular on the right, what you see is that the GORs for horizontal are also approaching sort of the 4.5 mark or so.
I don't have the straight edge in front of me, but it's about that which is similar to the vertical. I don't know whether it'll end up at 5 or 4.5 or what, but it looks like it's sort of reaching a similar sort of number.
We don't know the exact final number, but it shouldn't be materially different than the vertical wells, but we shall see. The main message for the call today is that we didn't really expect the GORs to go up as fast.
It didn't -- they didn't go up as fast in the vertical wells, but that's easily explained by the fact we're touching more rock, we're drilling higher pressure wells and we reached bubble point a lot faster on these wells and therefore, the gas comes at you. So we just didn't have that factored in from an engineering standpoint because we didn't have any data to tell us that until this -- principally this year.
And so that's why we sort of missed on the GOR forecast. But let's reiterate, this is a good thing.
Getting more gas and NGL out of these wells is a very good thing. It's extra economics and extra reserves.
That said, I think you're on point that we will now, as we have in the past, be focused on making sure we have of enough gas processing facilities to deal with the incremental gas. Toward that end, Targa going to be planning a new gas plant coming in first quarter next year and one in the third quarter next year to address these exact questions.
In the meantime, I think we're okay on gas processing space. But I think we'll have to look at that as we go forward because we may actually -- even though we've been using 200 million cubic feet a day incremental plants, we may want to increase that size.
But this certainly bodes for the Permian Basin producing a lot more gas without a doubt.
Ryan Todd
Okay. And then maybe -- that was a very helpful.
And then maybe one on the Eagle Ford. Can you talk a little bit -- I mean, you talked about the program that you're going to be drilling over the rest of this year.
Can you talk about your plans for the Eagle Ford going forward? And what impact the current drilling efforts could have on its eventual position within the portfolio?
Timothy Dove
Well, certainly, one of the objectives here is to find out how productive these wells can be. And here, I mean utilizing a more standard or let me just say close to 3.0 style Permian Basin frac design and longer laterals like we do in the Permian Basin and wider-spaced wells.
As you recall, we got probably 2 closely down-spaced the last campaign. That's a critical thing to be testing.
You realize we're only doing a limited number of wells. But nonetheless, it should give us the data to decide what are the relative economics of the Eagle Ford going to be going forward versus our other investment opportunities.
Eagle Ford has a bit of a challenge because you're speaking of gas oil ratios, I mean, it only produces 1/3 oil. So it is behind the eight ball a bit when it comes to commodity prices.
But that's something we have to decide when we get to that point. The main thing we want to do is get the technical data out to support that we can actually drill highly economic wells and then we'll decide where to go from there.
Operator
And moving to our next question, we'll hear from Charles Meade with Johnson Rice.
Charles Meade
If we could go back -- I know you've already spent some time, Tim, on the Slide 7, but if we can go back and talk about that a little bit more because I really feel like it's the crux of what's happening in this quarter. And I'm wondering if you could help guide interpretation here.
There's at least 2 interpretations I can't think of or have heard this morning. One is that if you look at the months of April, May and June, that, on average, you were 15 wells behind your plan.
And so if you think production from 15 new wells was flushed production, that, honestly, more than fills the shortfalls versus the oil...
Timothy Dove
Exactly. You can actually do the math precisely like you're doing it.
And what you're getting to is the same point I mentioned early, Charles which -- earlier which is the notion that you -- all of those times that you're behind in the schedule -- remember we're you're showing detail by month, of course, all that time you're behind you're losing production days for all the wells that were pushed back. And so, by definition, production days equals production.
That's what you see at the top curve. We could've shown you a graph of production days too, we lost, but it becomes esoteric at that point.
We just decided to show you production. But you're exactly on the right point.
Charles Meade
Got it. So one of the alternative interpretations here, though, is that if you look at where you were in March, you're 6 wells behind.
And where you are in June, you're just 11 wells behind. And so in that interpretation, you just met 5 wells which doesn't really fill the gap.
But I think if I understand you, Tim, the difference is when those wells came on and the catch-up late in the quarter. Is that right?
Timothy Dove
Right. Yes, you can look at the -- if you look at the orange bars, you can see -- the nuanced way to look at this is, in April, we completed 9 wells and then 23, then 29.
So not only was it back-weighted in the quarter, but most of the June wells were in the last half of that month. In fact, what do we say, half the wells in the quarter were backed up into that month.
So it's -- again, it's exactly the same concept that you -- when all -- that orange bar is below the blue when you're losing production days and that's all it is.
Charles Meade
Got it.
Frank Hopkins
Charles, this is Frank. If you want to call me later, I'll take you through all the actual numbers of what was in the budget and what's actually -- what we had for 6 months forecast in that.
Timothy Dove
We can give you details, Charles, on production days.
Frank Hopkins
We'll give you more detail than you want, yes.
Timothy Dove
It's get pretty weird when you're talking production days.
Charles Meade
Well, I might be weird enough to understand it. But let me ask one other question.
Tim, I like those graphs you put in about the trends in the gas-oil ratio and about how you're getting there quicker with horizontal wells. I'm curious, I imagine you've probably looked at that trends and broke it down by the version of completion and that you -- I imagine, you'd be getting there quicker with the Version 3.0 than you did with Version 1.0, hitting that whether it's 4,500 or 5,000 GOR ratio.
Is there -- is that on the right track? And is there anything you can share on that front?
Timothy Dove
Sure. I think what you would say, first of all, is the deeper the well, the higher pressures the wells is and, by definition, the higher it is that the volumes come at you including gas.
And it's typically the case, you reach bubble point faster in those wells also. Realizing, on these wells, we've reached the bubble point in 2 or 3 months after they're first put on production.
So the idea that you should see some radical change in production when to hit bubble point just doesn't make any sense. We hit bubble point down there instantaneously from the center point of the history of the well.
And so, really, what you see is, here, the faster the GOR goes up, it's more related to depth. It's also related to which zone and where you're producing, it's not the same across the entire field.
So our modeling will need to entail, as you kind of alluded to, what's going to be the GOR by well, what -- is it going to be by zone, by what location and so on. We're going to micrometer the thing a little bit more to get very, very accurate for 2018.
This is where we made the error in 2017, we just used kind of the -- any current data as of the end of '16.
Operator
And we'll take our next question from Brian Singer of Goldman Sachs.
Brian Singer
Just a follow-up on the Slide 7. The issues that spawned the delays and the need for the extra layer of casing began in February, you're already about 14 wells behind at the end of April.
As we look forward, are there any other risk to the upside or downside to production guidance for the rest of the year? It could be in a similarly early stage now that may be worth highlighting.
Timothy Dove
I'm familiar with the upside case for sure which is to do it -- if we end up going through more 3.0+ wells, we could see incremental production coming out of that pretty clearly. I don't have anything to report for you regarding anything on the downside.
Brian Singer
Great. And then also a timing question.
There's usually a lag time between when wells are drilled and when they're POP'd. As we try to disaggregate the POP and impact of GOR on gas production, but neutral on oil production, in the second quarter in the Permian Basin versus the timing of wells, was there a material impact from the delayed POPs on second quarter oil production?
And if not, why didn't we see a greater move up in oil production during the quarter?
Timothy Dove
That's exactly correct. We were still experiencing delays really in the May and slightly into June before we really tackled the 4-string casing design.
And then you see that in the POP schedule really accelerating in the second half of June. It's exactly the same point that Charles was referencing which is we lost production days compared to that plant.
So you can see that, for example, in the slide you're referencing, Slide 7, we were 20 POPs behind in May. We caught some back up in June, but they're all in the end of June.
So guess what happens? You lose the production from those wells that was counted on for June.
It just is what it is.
Operator
We'll take our next question from John Freeman with Raymond James.
John Freeman
Just one from me. When you look at the extra cost in days on the casing design change combined with the fact that given the better GOR expansion, you're able to increase the EURs on the Wolfcamp zones.
Does it sort of change the way to think about maybe the mix of Wolfcamp/Spraberry wells going forward, like in the long term plan?
Timothy Dove
Well, I think everything we do is based on economics. Everything is based on returns on the wells.
So theoretically, in a lot of the shallower zones, we don't have this issue that's as substantial, that is the pressure-related issues. And -- but the point is -- I'm talking about the pressure issues and since you're on the south also, you can have less issues in the south.
But the point is I think we just look at the economics every day we drill a well and decide what's the implications of the well cost increase for the new design, what are the implications of the amount of returns as they increase with more -- higher GOR and, therefore, more gas and NGLs. And so, therefore, yes, we'll be evaluating that.
But we've got excellent economics across this field, John, as you know.
John Freeman
No, I guess, I was just trying to look at it as, at the end of the day, the GOR expansion is a good thing like you said. So if the Wolfcamp B has gone from 1.5 to 1.7, A from 1.2 to 1.3, then it seems like that would maybe cause a little bit of a push towards more Wolfcamp.
But...
Timothy Dove
As you know, we love the Wolfcamp B. It's been the predominant of the wells we drilled in there.
But it just so happens now we're coming back and drilling the Wolfcamp As underneath -- above the Bs, I should say and that program has been very successful. So I think we just kind of continue with that kind of a program.
Yes, I don't know if Rich mentioned this, but it's true. That also allows us -- when we go from the Bs and then go after the As above them to utilize existing facilities.
So our facilities' capital needs are less that way.
Operator
Our next question will come from Scott Hanold with RBC Capital Markets.
Scott Hanold
So specifically on the drilling pressures you all have seen, I'll just kind of throw it all into one question. Can you specifically talk about the particular zone that is, will be the first part?
And then is there an option to look at other deeper zones to utilize instead of that? And then the third part of the question is if you did do more water recycling, what is the cost associated with that in your view?
Timothy Dove
Yes, thanks for the question, Scott. First of all, the formation in question where most of the injections have been done for decades is the San Andres formation, it's about 3,000 or 4,000-foot deep.
As to alternatives that are deeper, we actually are heavily investigating those right now. Some of the deep zones have decent potential.
We're probably cutting edge right now from the standpoint of understanding from a geological standpoint what it is that those zones could take as to produce water. We're actively studying that and have a team of geologists working on that.
I don't know of anybody else in the an industry that's got the team we have working on that. And so we'll get that unlocked.
The question is going to be can you drill those wells and have them be economic versus your alternatives? And that's going to be your question, because they're going to be deeper wells.
The third is recycling. Now recycling is not a material cost item for us.
We just take produced water, slightly clean it up and reuse in fracs. So there's not a big cost in that other that it's already embodied in the capital of the water system because this will eventually be incorporated into and a part of our water supply system.
So you can count the capital as already contributing towards the solution.
Scott Hanold
Okay. So you are, as you build up the water infrastructure, that recycling's part of it.
So in theory, from a bigger picture perspective, it should mitigate itself naturally. Is that how I'm hearing it?
Timothy Dove
Well, it will for us. I mean, we're the ones who have the big water system.
I don't know if that's true across the board. But certainly for us, that's the case.
Jerome Hall
Yes, Scott, this is Joey. I think you're hitting on a key point, that our water infrastructure is a critical piece in allowing us to -- and it's really I would call it reuse more than recycled because the amount of effort that we have to put into reusing the produced water is pretty minimal.
And then you add to the fact that we have the Odessa water that we can blend it with and all of our Santa Rosa and the massive infrastructure that we have, we're able to manage this. It's just a matter of reaching the critical mass to where you have the timing issues worked out.
Because where you produce it and where you need it, as you drill more wells, it becomes easier to manage. And that's why you'll see us here in the near term and the near future continuing to use more produced water.
And it's something we've been doing that for a while and we continue to move that up. So it's a pretty easy issue to manage.
Scott Hanold
Yes, is there a time frame which you guys think that the infrastructure could be well in place? Is it over the next couple of years?
And it is an option just to shut down some of the vertical wells that may be causing most of the issue because we they, honestly, probably don't produce as much as some of these horizontals do on a hydrocarbon basis?
Timothy Dove
Yes, I think the way you have look at vertical wells is a lot of these wells are very low producers now, as I showed the curve, 40 years into their lives, so they don't produce much liquid of any form. We wish they'd produce more oil, but they don't produce much volume of anything.
So that's really not an issue. I mean, they wouldn't have any real contribution to shut in a significant number of vertical wells.
But the bigger picture -- answer to your question is, yes, the next -- I'd say between now and the end of next year, we will have a full, ready to rock 'n roll produced water reuse system in place in the field. And we start to then mitigate the issue.
Scott Hanold
Yes, Tim. So just to clarify.
I guess my question on vertical wells is why not shut them in and so they don't produce the water creating more capacity to inject into San Andres?
Timothy Dove
What I'm telling you is the vertical wells, on average, don't produce much water anymore because they don't produce much of anything. So they're -- I mean, you have these 5, 10 barrel a day wells of which 80 -- you're going to have similar amount of water on a system basically.
So the point is that's not going to solve the problem. The bigger issue is as we drill horizontal wells, we're injecting much higher volumes of water and that's probably more a contributor than anything to do with vertical.
Operator
We'll take our next question from Neal Dingmann with SunTrust.
Neal Dingmann
Tim, when you see what acreage price are going for around your area, what are you guys thinking about? And kind of given what your NAV looks like, I think, very underappreciated.
Just maybe talk about M&A potential more on the sales side.
Timothy Dove
Well, the sales side. Well, I think the way I would couch that is one important note to make is we mostly have Tier 1 acreage, okay?
That's important. So we don't have a lot of slacky acreage sitting around here that we would say automatically, "This needs to be peeled off because it's substandard."
That said, we're doing, as you know and we've talked about a quite a bit, quite a large number of trade still to block up our ability to drill long laterals. And so that continues.
We have deals going all the time there and those are extremely valuable deals where no cash assets between the hands, but nonetheless, the size of the pie increase for both parties, with both parties in that trade end up having longer laterals they can drill. So as I said, the pie gets bigger.
But if you look at some of the most recent acreage transactions, let's start with the 5 handle, all of our acreage is basically, with the exception of what we acquired from Devon, has basically 0 handle on the basis. So it wouldn't make any sense for us to do that.
Operator
That will conclude our question-and-answer session for today. I would like to turn the conference back over to management for any additional or closing remarks.
Timothy Dove
Thanks, everybody, by being on the call. We appreciate your time.
Like I said earlier, I hope you enjoy the rest of this summer. We will look forward to seeing you when the season begins early September.
And look forward to more conversations on these points. Thanks very much.
Operator
That will conclude today's conference. Thank you all once again for your participation.