Nov 3, 2015
Executives
Frank E. Hopkins - Senior Vice President-Investor Relations Scott D.
Sheffield - Chairman & Chief Executive Officer Timothy L. Dove - President, Chief Operating Officer & Director Richard P.
Dealy - Chief Financial Officer & Executive Vice President
Analysts
John A. Freeman - Raymond James & Associates, Inc.
Charles A. Meade - Johnson Rice & Co.
LLC David W. Kistler - Simmons & Company International Doug Leggate - Bank of America Merrill Lynch Brian A.
Singer - Goldman Sachs & Co. Stephen Richardson - Evercore Partners Inc.
Evan Calio - Morgan Stanley & Co. LLC Michael A.
Hall - Heikkinen Energy Advisors Leo Mariani - RBC Capital Markets LLC Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Operator
Welcome to the Pioneer Natural Resources third quarter conference call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Senior Vice President of Investor Relations.
Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.pxd.com.
Again, the Internet site to access the slides related to today's call is www.pxd.com. At the website, select Investors, then select Earnings & Webcasts.
This call is being recorded. A replay of the call will be archived on the Internet site through November 28.
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 and 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, Frank Hopkins.
Please go ahead, sir.
Frank E. Hopkins - Senior Vice President-Investor Relations
Thank you, Destiny. Good day, everyone, and thank you for joining us.
I'm going to briefly review the agenda for today's call. Scott's going to be up first.
He'll provide the financial and operating highlights for the third quarter of 2015, a great quarter for Pioneer, especially when you recognize the current low commodity price environment that we're operating under. He'll then discuss our latest outlook for the remainder of 2015 and provide some comments on the three years that follow.
After Scott concludes his remarks, Tim will review our third quarter horizontal drilling results in the Spraberry/Wolfcamp and the Eagle Ford shale. He'll also provide details regarding the latest plans for our Spraberry/Wolfcamp infrastructure prospects.
Rich will then cover the third quarter financials in more detail and provide earnings guidance for the fourth quarter. After Rich concludes his remarks, we'll be glad to take your questions.
So with that, I'll turn the call over to Scott.
Scott D. Sheffield - Chairman & Chief Executive Officer
Thanks, Frank. Good morning.
On slide number 3, we had an adjusted loss of $1 million or $0.01 per diluted share for the third quarter. What's more important, obviously, we had a tremendous quarter in regard to production growth.
Third quarter production, 211,000 barrels of oil equivalent per day, 52% oil. It was 7% above the second quarter and above the top end of guidance of 205,000 to 210,000 [BOE per day] for that quarter.
Obviously driven by the strong Spraberry/Wolfcamp horizontal drilling program. That production was up 15,000 barrels of oil equivalent per day or 13% versus the second quarter.
The oil production actually increased 10,000 barrels of oil per day. What's probably more important is the fact that this growth is coming from only six rigs in the north and a net 2.4 rigs in the south, so really only 81/2 rigs coming out of the Permian Basin.
You'll see later, as we discuss the additional eight rigs that we've added, you'll see that growth coming on late first quarter going into a tremendous strong second quarter of 2016. Updating 2015 full-year production growth forecast to 11% from our 10%-plus.
If you look at the Spraberry/Wolfcamp full-year growth rate, it was 22% to 24%. We're upping that to 25% to 26%.
Continuing realizing tremendous cost reductions and efficiency gains. Achieving already 25% decrease in drilling and completion costs compared to 2014, expect it to get greater than 30% going into 2016.
20% reduction in horizontal tank battery costs compared to 2014. Expect that to be greater than 25% going into 2016.
Continue to see reduction in LOE, 18% reduction already compared to the third quarter of 2015 compared to 2014. Continue to see that with efficiency gains, we're continuing to see our horizontal pad spud-to-POP times reduced to 135 days.
A lot of it's reflecting the reduced drilling time by seven days per well. Going to slide number 4, we did place 33 horizontal wells on production in the third quarter.
In the north, in the Spraberry/Wolfcamp, continuing to see tremendous results from the Wolfcamp B and Wolfcamp A intervals. 30 wells, they're all on average tracking greater than 15% above a million-BOE type curve.
We'll evaluate increasing that sometime next year. Average 24-hour peak rate for the 30 wells, 1,900 barrels of oil equivalent per day with 78% oil content.
19 of the 30 wells benefited from completion optimization, which Tim will talk more about, 17 Wolfcamp B wells and two Wolfcamp A wells. Again, the average production from all the Wolfcamp B and A wells drilled since 2013 in the north continues to track EURs of 1 million barrel of oil equivalent.
We did close the sale of our Eagle Ford Midstream business in July for $2.15 billion gross or $1 billion net to Pioneer. Received net sale proceeds of $530 million at closing.
An additional $500 million will be received in July of 2016. Resulted in a book gain of $778 million before tax or a seven-time return on investment in five years.
This is another great example of infrastructure spending that we do, unlike a lot of our peers, and turn it into a tremendous gain. Strong balance sheet with cash on hand at $600 million at the end of the third quarter of 2015.
Again, we probably had the strongest hedging position when you look at the years 2015 and 2016 of anybody in the U.S. We were hedged 90% for 2015, 85% for 2016 on oil and 20% for 2017.
On gas, 85% for 2015, 70% in 2016. When you look at what we've collected and what the current value of our entire hedge book is, it's about – approximately $1.5 billion for the years 2015 and 2016.
Continuing to forecast production growth of 15%-plus over that 2016 to 2018 time period. All growth of 20% plus.
Again, due to the efficiency gains and higher EURs in the Spraberry/Wolfcamp, we continue to expect to deliver forecasted growth using fewer rigs in the Spraberry/Wolfcamp than the 28 rigs that we had previously anticipated and announced. Eight rigs have been added in the north between July and late October.
No further rig additions planned for 2015. Currently at 18 rigs, 14 in the north and four rigs in the south.
Obviously, the timing of future additions over this next three-year time period dependent upon the incremental efficiency gains, further productivity improvements, obviously commodity prices, while we're continuing to achieve strong well returns. The current IRRs in the Spraberry/Wolfcamp ranged from 45% to 60% at current strip prices, as noted in footnote 1 at the bottom of your slide.
Continue to operate six horizontal rigs in the Eagle Ford. With six horizontal rigs and our modeling over the next three-year time period, we expect to keep production essentially flat versus the third quarter of 2015.
On slide number 6, our capital program continues to stay at $2.2 billion. That includes the eight additional rigs we've added in the second half of 2015.
Drilling capital still the same at $1.95 billion. Again, funding primarily through cash flow of $1.5 billion, cash on hand $600 million at the end of September, and addition with our great hedging program in 2015.
Going into slide number 7, again, forecasting – again, targeting 15%-plus production growth over the next three-year time period, 2016 to 2018. Summarizing 2015, we'll end up averaging somewhere between 202,000, 203,000 barrels a day.
A key footnote, going into the fourth quarter with our guidance at $206 million to $211 million, we will have one-third fewer POPs in Spraberry/Wolfcamp and the Eagle Ford compared to the third quarter. That's why guidance is essentially flattish going into the fourth quarter.
Again, I'll remind you, you'll see the major impact of the additional eight rigs late first quarter of next year and going into the second quarter of 2016. Again, looking long term, 2016 to 2018 reflects increasing oil productivity, capital efficiency improvements, strong well returns, and increasing horizontal rig count.
We'll be moving up to about 60% oil by 2018. Oil growth will be 20%-plus in that three-year time period.
I'll now turn it over to Tim to get more specific on our horizontal results.
Timothy L. Dove - President, Chief Operating Officer & Director
Thanks, Scott. I'll start with slide 8, and it shows that the third quarter continues our track record of excellent results in the drilling and completing of Spraberry/Wolfcamp wells.
And toward that end, as Scott has already mentioned, we put 33 wells on production, horizontal wells. The predominant number, of course, is the Wolfcamp B, with 28 of those 33, with two Wolfcamp A wells.
It should be noted that, according to our plan, these A wells were drilled after some delay from when the corresponding B wells were drilled. And this will be our plan still going forward.
As you can see on the graphs in both cases, the production results are quite outstanding, and we estimate that the early production is tracking over 15% above our million-barrel-BOE type curve, which was just simply outstanding. We did put a couple other zones – wells on production, particularly two Wolfcamp D wells, which had excellent producing rates of about 1,600 barrels a day in the first 24 hours, and then a Lower Spraberry shale well that we still don't have any significant results for.
The optimization program, I think, is contributing very mightily when it comes to the encouragement we see on production. 26 completion optimization wells were put on production over the last couple of quarters, and if you take a look at the 30 wells above, they clearly are being affected by that.
We've seen pretty significant increases across the board when it comes to completion optimization, when it comes to optimizing the stage lengths and increasing the number of clusters per stage, increasing fluid volumes, and proppant. And so the 26 wells, among the total that have been put on production the last two quarters, have really seen significant increases.
Actually, in one particular case, we have an offset well that has shown about a 34% increase in its EUR versus the offset well. So it's clear that we need more work and more time for the optimization, and it's also clear that optimization won't be the same in every zone, in every area of the field, but it's very encouraging what we're seeing, to the point where we're actually expanding our optimization program.
We'll be testing an additional 50 wells in the fourth quarter this year, as well as into the first quarter next year. Turning to slide 9, as we've done for several quarters, the graphs on the left depict the actual production from all of the wells that we've drilled in each of the Wolfcamp A and B intervals.
And you can see on average – in this case we've got significant data sets for both – these wells have averaged roughly about 1 million BOE in both the Wolfcamp A and the Wolfcamp B. If you take a look at the map on the right, we've got a substantial data set that's being developed with all these wells and across a large swath of the acreage.
As I mentioned on slide 8, it's pretty clear that these drilling results on average are going to increase. Our averages will be pulled up by virtue of the increased EURs per well that we're seeing, and I think you'll see these curves move upward as we move into the future.
On slide 10, the economics of drilling in this field still strongly support drilling longer laterals where we can do so. The table clearly shows that.
It shows the cost incrementally of drilling longer laterals and then the incremental amounts in terms of EURs, and the NPV per well dramatically increases from the case of a 5,000-foot lateral of about $2.3 million up to about $8 million for a 10,000-foot lateral. So very significant improvement in the payout and the NPV per well in doing so.
As the graph at the bottom shows, it's pretty clear that the higher prices go, there's even a more significant NPV lift that we get from drilling longer laterals. Our position in the basin is such that the vast majority of our acreage supports longer laterals.
And that will allow us to drill, say, 7,500- to 10,000-foot laterals really for decades. As depicted in the cartoonish map here, you can see that if we only had one section by one section of 640 acres, that would limit us to only 5,000-foot laterals, but in our case we have contiguous acreage, in many cases where you at least have two sections stacked north and south, and we can drill up to 10,000-foot laterals.
And so we have a significant advantage compared to peers in that our substantial acreage position is contiguous and allows for the drilling of long laterals. On slide 11, even with the longer laterals, our drilling time per well has decreased substantially over the last several quarters, as seen in the graph.
In fact, it was down seven days from 32 to 25 in the third quarter compared to the second. This shows all wells drilled in the Wolfcamp B.
You can see the dramatic benefits we get from focusing on one zone and getting better and better at drilling that one zone, to the point where our best wells to date in the north has been 17 days in terms of drilling and in the south 13 days, given that that southern area well was much shorter lateral than in the north. But the objective should be, as we move forward, to move the averages down even further to correspond to the best wells drilled to date, and I think you'll see that improvement continue as we go into the future.
A lot of this has to do with utilizing a modified three-string casing design and, as I mentioned a minute ago, focusing on one particular zone, and in this case being the Wolfcamp B predominantly. And then turning to slide 12, this is an update on activity in the north.
As Scott mentioned, we have 14 rigs running horizontally in the north with no plans for additional new rigs in the north during this year. We will be actually POP-ing a number of wells that's actually larger than our original plan, even with adding only the eight rigs that we have since July 1.
The average spud-to-POP times are coming down – this is in relation to the reduced drilling days I mentioned a moment ago – and I think that will continue as well. I think we're down to roughly 135 days in the north.
The cost per well has come down dramatically. This has already been mentioned, but about 25% is what we see as the cost reduction so far year to date in the north, bringing the well cost down to just over $8 million.
And I think this can be reduced another 5% or so as we get into early next year and we see the full effect of the reduction in tubulars, as well having some of our rigs that are under contract today be renegotiated at lower spot rates. Our program still calls for us averaging 1 million BOE that would generate IRRs at 50% to 60% in the north.
That includes an allocation for tank batteries and saltwater disposal. As I mentioned earlier, to the extent we're actually drilling EURs that are substantially above 1 million barrels, it seems in the third quarter, I think we can probably surpass these economics as we go forward, in large part due to the benefits from completion optimization.
If you look on the map at the right, we will be planning to POP about 110 wells this year. 76 have already been accomplished through the end of the third quarter, and most of these wells, as I mentioned earlier, will be focused on the Wolfcamp B, with decent number of Wolfcamp A and Lower Spraberry Shale wells in the mix.
On slide 13, this shows similar data for the Southern Wolfcamp area, where we have been drilling with four rigs, really, for the majority of this year. I'd say most of the statements I made for the north apply for the south as well, where the results look very, very good.
We're seeing strong EURs and efficiently gains coming out of cost reductions. Costs down here are just over $7.5 million, owing to the fact that we're drilling in this area slightly shallower wells, and we'll see cost reductions, I think, further, just as we expect in the north, down to about 30% reduction compared to last year, getting them down in the low $7 millions by the time the early part of 2016 comes around.
And IRRs down here being about 45%, slightly less productivity in the south compared to the north, and that results in the lower IRRs. But we'll POP about 85 wells down in the south.
Again, the majority being Wolfcamp B. Turning to slide 14, the results of this outstanding drilling campaign is a phenomenal quarter in terms of production growth.
Production grew here 15,000 barrels a day from the second quarter into the third quarter. That was as a result of POP-ing 52 wells, with 33 in the north and 19 in the south.
Production was up about 13% and significant increases, of course, in our oil production as well. For the first time, interestingly, we've ever seen in the history of the company, the horizontal production in this field has now surpassed vertical.
As we're drilling very few vertical wells and the vertical wells decline, expect horizontal to take over in a significant way going forward. Scott mentioned the fact we're going to see a slight production decrease in the fourth quarter, flat to down slightly.
This is just simply a matter of POP timing and the number of POPs. So we had significant number of wells from our July and August campaign that we're just going to be POP-ing at the very end of the year.
And, as a result, they don't have much impact on the quarter. And the actual number of POPs in the quarter will be dropping to the extent of about 30% – 20% to 30%, just with the timing of those POPs.
And so I think what you'll simply see is the POPs will increase beginning going into the first and second quarter, and this is when you'll see the production bump. Interestingly, the fact is we're getting to these wells faster, and so what's happened is we've moved some wells we'd otherwise planned to be POP'd in the fourth quarter, those got done in the third quarter.
So that's why you've seen very substantial growth in the third quarter and a flattening in the fourth. But, overall, the results are simply outstanding.
We're growing this field % to 26%, which is higher than we had anticipated going into the year. So really outstanding results in the third quarter, and I anticipate that'll be the case for the year as well.
On slide 15, of course our objective when it comes to infrastructure is to optimize the buildout so that we can prepare for the future but also within the constraints of today's commodity price outlook. And so you'll see us in some cases trying to limit what we need to spend on infrastructure but also moving ahead on these projects.
So for instance, when it comes to tank batteries and saltwater disposal facilities, we're spending about $175 million this year. Expect about $200 million next year for those same expenditures.
But realizing we'll be POP-ing probably about 20% more wells next year, the cost per well is actually coming down by about $50,000 to $75,000 per well to hook up those wells. In gas processing, one thing you've seen, I think, is the robust nature of the Permian Basin production is really probably the foremost system when it comes to new oil wells and production in the United States in light of the low commodity prices.
And toward that end we need to put our new Buffalo plant in place in the second quarter next year. We spent about $70 million preparing for that this year, and we'll spend another $50 million putting it on production in the second quarter.
Again, just because it's – these systems are filling up faster than we would have otherwise anticipated as production continues to be robust in the Permian. A water distribution system will still require capital.
We spent about $130 million this year for a combination of engineering and putting in place right-of-way for the new pipeline systems, laying some of that pipe, and connecting the Odessa water system, as well as other water sources. I think we'll spend a similar amount next year.
It will be more focused on subsystems for moving water within our field, as well as developing frac ponds to store water so that we're ready to go in the campaign for drilling in the next few years. We still are moving ahead with the notion of buying the effluent water also from the City of Midland, and that those discussions are proceeding well.
On the sand mine front, of course, we spent about $75 million this year to prep for an expansion. I think that expansion is not something we really need this year or next year; it's probably going to be the latter part of the decade as we determine we need more sand in terms of the demand from the rigs, and when we do so that expansion will cost about $75 million.
And then finally turning to Eagle Ford shale – that's slide 16 – we put about 36 wells on production in the third quarter, a mixture of upper and lower targets. We've POP'd about 85 wells so far with 100 targeted for the year.
Of course, third quarter production was down slightly. We've seen some well performance issues that really result from changes we made earlier this year.
In the face of the need to reduce costs, we changed the completion techniques to reduce fluid concentration, as we had some evidence from some earlier wells that could actually work and cut costs. It turns out, as we look back, that probably had a negative effect on production.
It's masked simply because these wells, generally speaking, on day one are choked back, and so accordingly you don't really see much of an impact in terms of the production curves until later in the life as the pressure comes off of the well. And accordingly we really didn't see this till about six months after this change was made.
So we're going to be remediating the situation, as you might expect. So, commencing immediately, what we're doing is using higher fluid concentrations.
We're also going to be pumping more proppant, shortening the stage lengths, and tightening the cluster spacing, really putting the hammer to this field to get it back online in the type of trajectory we would expect. The plan still is to continue with the six rigs that we have running today.
That's down from nine that we had last year. Six rigs, in effect, is the number of rigs to keep production essentially flat, I think, going forward.
We'll have only about 15 POPs in the fourth quarter compared to 36 in the third, and the timing of that, of course, is reflected in the overall company production forecast for the fourth quarter being flat or slightly down from the third quarter. So with that I'm going pass it to Rich for a review of the third quarter financials and his outlook for the fourth quarter and for the rest of the year.
Richard P. Dealy - Chief Financial Officer & Executive Vice President
Great. Thanks, Tim.
I'm going to start on slide 17, where we reported net income attributable to common stockholders of $646 million or $4.27 per diluted share. That did include mark-to-market derivative gains of $214 million after tax, or $1.42.
In addition, it had the gain on the sale of Eagle Ford that Scott mentioned of $499 million after tax or $3.29. And then $66 million, or $0.45 of other charges that hit during the quarter, primarily related to the impairment of our South Texas Edwards gas field during the quarter.
So, adjusting for those items, we're at a $1 million loss, or $0.01 per share. Looking at the bottom of the slide, where we show results for the quarter versus guidance, you can see that production was above the top end of the guidance that we talked about.
All the other items going down that list were either within guidance or on the positive side of guidance. So won't spend much time on those, other than just to point out as – in addition to the cost reduction issues we've talked about on capital and LOE, we're also seeing our G&A costs per BOE come down.
We're down about $0.50 per BOE this quarter compared to the third quarter of last year, and same on a year-to-date basis. Turning to slide 18, talk about price realizations.
As obviously everybody knows, commodity prices were down for the quarter. Oil price realizations for Pioneer were down 18% in the third quarter compared to the second quarter, down 12% on NGLs between the quarters, and then offset slightly by a 7% increase in gas prices.
If you look at the bottom of the slide, the company continues to benefit from our derivative portfolio, where we added about $20 per barrel to our oil prices because of our derivative position, about $1.28 on NGLs and $0.87 per MCF on gas. When you aggregate those up, that's about $238 million of cash flow that we had during the quarter, or about $600 million for the year in total.
And then our portfolio, as Scott mentioned, at end of September, was worth $775 million at that point in time. So continue to benefit strongly from our derivative position.
Turning to slide 19, looking at production costs. Production costs were up slightly for the quarter, about 4%.
Most of that is what we talked about on our last earnings call, was coming from the third-party transportation costs going up about $0.75 to $1, as expected, due to the sale of our EFS midstream business. That was offset by taxes coming down with the lower commodity price environment.
And then as you can see with the base LOE, you can see that we've continued to benefit from our cost-reduction initiatives there, and we're down 18% relative to 2014 on base LOE. So good progress on production costs in total for the quarter.
Turning to slide 20, looking at our liquidity position, the company continues to maintain an excellent balance sheet, with $581 million of cash on hand, net debt of $2.1 billion at the end of the quarter. Our liquidity position still is excellent, with not only the cash on hand but $1.5 billion unsecured credit facility that is completely undrawn.
We did, during the quarter, extend its maturity out to August of 2020. So, overall, continue to have a strong balance sheet, and we – as Scott mentioned, we have another $500 million coming in from the proceeds of our EFS midstream sale in July of 2016.
Switching gears and talking on slide 21 about Q4 production guidance and other guidance items. Production, as Tim talked about, is flattish to slightly down, just given the decrease in POPs in the fourth quarter and just timing of POPs during the quarter.
You'll see our production costs – we adjusted that guidance down to $11 to $13, down from prior quarters, just reflecting the company's cost-saving initiatives that are ongoing. Probably the couple other items worth noting is DD&A guidance is slightly higher, just reflecting that we'll have another quarter of lower commodity prices.
And since we used the trailing-12-month average, we do expect to lose some end-of-life reserves on producing wells, causing our DD&A to slightly increase. Other expense of $40 million to $50 million does include $18 million to $20 million of stacked rig charges, down as we put more rigs back to work, from $22 million that we saw in Q3.
And then current income taxes are $10 million to $20 million, really reflecting that we'll recognize in the fourth quarter the last portion of our AMT tax associated with our EFS midstream sale. So with that I'll probably stop there, turn it over to you, Destiny, for questions.
Operator
Certainly. And we'll take our first question from John Freeman of Raymond James.
Please go ahead.
John A. Freeman - Raymond James & Associates, Inc.
Good morning, guys, great quarter.
Timothy L. Dove - President, Chief Operating Officer & Director
Thanks, John.
John A. Freeman - Raymond James & Associates, Inc.
The first question, when I'm looking at the longer-term guidance where you're maintaining the prior growth rate despite the less rigs, is the way to sort of think about it or the way that you all are looking at it right now is you're you know you're going to need less rigs than the 28 you previously guided to, but the efficiency gains are happening so quickly, the type curve, production relative to the type curve keeps improving, there's just – you don't quite yet know what that rig count is; you just know it's less, and at some point early next year we'll get some more color on that?
Scott D. Sheffield - Chairman & Chief Executive Officer
That's it – that's exactly, John, you're reading it exactly right. So it's taken a lot less rigs between July 1 of 2015 and end of March of 2016 than we thought, and we'll give out more details as we get into next year's budget.
But really, even if – I don't see current prices staying where they're at, but if current prices stay where they're at, even under that scenario we would add only two to three rigs per year over the next three years. So with increased efficiencies, getting much higher type curves, we're seeing tremendous – going to be much easier to hit that 15% target.
John A. Freeman - Raymond James & Associates, Inc.
Okay, great, and then just my one follow-up, when I think about sort of the mix of the wells next year, if we just looked like at the north, where you've got kind of 80% Wolfcamp B, 10% A, 10% Lower Spraberry, should I expect the mix in 2016 to be similar? I mean, I know you're encouraged by the Lower Spraberry, but also don't want to lose any of the progress on the efficiency front, so just maybe how to think about that.
Timothy L. Dove - President, Chief Operating Officer & Director
Yeah, John, I think the way to think about it is you'll see that we'll probably have a larger number on a percentage basis of A's and Lower Spraberry Shales next year than we did this year. We haven't established the exact percentages yet, but you're not going to see a year where we drill 80% to 90% B's next year, because we do need to make progress on A's and Lower Spraberry Shales as well.
We'll get back to you as soon as we kind of pencil in the exact numbers, but I would say a substantially bigger percentage of A's and Lower Spraberry Shales.
John A. Freeman - Raymond James & Associates, Inc.
Great. Thanks, guys.
Congrats again on a great quarter.
Scott D. Sheffield - Chairman & Chief Executive Officer
Thanks.
Operator
And we'll take our next question from Charles Meade from Johnson Rice. Please go ahead.
Charles A. Meade - Johnson Rice & Co. LLC
Good morning, Scott, and to the rest of your team there.
Scott D. Sheffield - Chairman & Chief Executive Officer
Yeah, hey, Charles.
Charles A. Meade - Johnson Rice & Co. LLC
Yeah, if I could just press a little bit further on how you're thinking about the rig adds and different scenarios. And I recognize that you guys have a lot of flexibility and that you don't have to make that decision now.
But you laid out a few scenarios or a few maybe conditions on slide 5 saying that incremental efficiency gains, further productivity improvements, and well returns are really what you're looking for to add rigs, but am I looking at it right that you really want to see more productivity gains from here in order to add rigs? Or, going back to your earlier comments, is it just with the current course and speed on both your operations side and on the commodity price side, that's sufficient to get two to three rigs a year?
How should we think about the scenarios there?
Scott D. Sheffield - Chairman & Chief Executive Officer
Look, first of all, we're being very conservative on these efficiency gains and well productivity. We're not modeling in the results we saw from this past quarter where we're getting greater than 15% above 1 million barrel type curves.
You got to realize the longer we see those wells continue to perform, the longer we see these efficiency gains stay and improve, we will eventually model that in. And over time, we continue to think we'll need less rigs than we're even seeing now.
So that's what we're saying primarily. And as long as getting – the key driver to all this is getting strong returns, number one.
I think oil prices have bottomed. They may stay in the $45, $46, $47 range for a while, but we're collecting, as you remember, on our hedges, $20 plus the current price on all of our hedges next year.
And so we're just way above the peers in regard to our hedge position. We think it's so important to continue to grow as long as the returns are great.
So as we see these gains occur, we'll model those in, and we think we can even need less rigs than we're even showing today.
Charles A. Meade - Johnson Rice & Co. LLC
Thank you, Scott. That's helpful.
And perhaps picking up on one of your themes there, if I could ask about your most recent batch of these 30 wells that you brought on that are showing that 15% above the type curve. One of the things I noticed on that is the lateral lengths on these wells are more like – they're averaging, call it 8,500 feet.
And so I suppose the question is, number one, is that what we should look for in your 2016 program, is lateral lengths of 8,500 feet? Or perhaps is it even going higher?
And the other question – and this may be torturing the data a little bit too much – but, Tim, in your prepared comments, you talked about how you put those two A wells – I recognize there are just two of them, but you mentioned about how you let some time elapse after drilling the B's on the same pad. And so I was wondering if you could maybe, if you have the data, compare how those A wells are doing with this completion optimization to the B wells on the same pad.
Timothy L. Dove - President, Chief Operating Officer & Director
Yeah, first of all, on your first question, Charles, I think as we move forward, of course, our land team has done a phenomenal job working to put even further adjacent acreage next to our existing acreage, to the point where I think our current planning would suggest 9,500-foot laterals in general on average, in both the north and south next year. And I made the case, as you remember, that that's a substantial value-adder, even compared to the 8,500 feet or 8,600 feet that we're dealing with this year so far – or in the quarter.
So it's going to be a dramatic increase. What I would say about the A's is we have systematically decided to wait on A's after the B campaign, and now that you see us coming back to A's, is what I mentioned to John's question, that the A campaign will increase simply because we're ready for it, having drilled the B's that correspond.
And so what we'll say is that we have a limited sample size of optimized A's; that's the two wells that we already mentioned. But they look great, of course.
But we're going to need a bigger sample size. But so far, if that's what we're looking at, we're looking at wells in the sense of the A's that correspond well to the B's and produce similarly.
Charles A. Meade - Johnson Rice & Co. LLC
Thank you, Tim.
Timothy L. Dove - President, Chief Operating Officer & Director
Yep.
Operator
And we'll take our next question from David Kistler from Simmons & Company. Please go ahead.
David W. Kistler - Simmons & Company International
Morning, guys.
Scott D. Sheffield - Chairman & Chief Executive Officer
Hey, Dave.
David W. Kistler - Simmons & Company International
Real quickly, with respect to these longer laterals, I know you outlined kind of decades of inventory, but what percent of your portfolio would you say is applicable to longer laterals, based on the Block E acreage?
Timothy L. Dove - President, Chief Operating Officer & Director
Well, if you take a look at the statistics, it's pretty mind boggling. I think about 75% of our acreage would be 7,500 feet or more.
And there's quite a substantial – I think over 50% would be 10,000-foot laterals, so it's – I don't have the exact number, but those are round numbers for you that are pretty close.
David W. Kistler - Simmons & Company International
Okay, appreciate that. And then when you think about the infrastructure that you've currently designed, do you have to add some increased infrastructure to handle these longer laterals, given the productivity increase?
Just any kind of color around that, or is that plan already factored in at this juncture?
Timothy L. Dove - President, Chief Operating Officer & Director
I think it's essentially factored in. I mean, you're talking about incremental volumes in terms of produced water, in terms of oil.
We're already planning for incremental volumes, and as you know, as you've worked with us, on – our tank battery designs are typically set up for 60 wells, so we've got plenty of capacity. I think the fact is these are already built for much higher volumes than we ever dealt with when it came to vertical wells.
David W. Kistler - Simmons & Company International
Okay. And then just last one, when you think about that 15% guidance through 2018 and kind of capital outlines, do you think about the D&C cost, is that capturing these longer laterals?
And is it capturing the uplift in production in the current guidance, or could we see what you're targeting for kind of the start of 2016, those well costs being a little bit more but obviously productivity being more?
Timothy L. Dove - President, Chief Operating Officer & Director
Yeah, I think you hit the nail on the head there. We're in a situation where we will have incremental costs that come from lengthening laterals on a percentage basis.
And, as I mentioned, probably going to 9,500 feet compared to 8,700 feet or 8,600 feet. But that's far more than offset by the fact that the incremental production from that will yield a result which significantly enhances the returns.
That said, I mean, everything we have built in today is using still the million-barrel type curve results. So we haven't built in anything over that, so that's a significant adder.
We're just now getting our arms around, as you can tell, the impact of reducing days on wells and the optimization effect of that in terms of needing less rigs to drill the same number of wells. That's what's leading us to the conclusion that we don't need to add any more rigs here during the latter part of this year to achieve the similar results that we thought we were going to need further – more rigs earlier on.
I think as you look forward, we'll be beginning through time to add into our modeling, as Scott has already referred to, some of these benefits we're seeing, but we're not adding all of those benefits in yet.
David W. Kistler - Simmons & Company International
Okay. Appreciate that color, guys.
Great work.
Scott D. Sheffield - Chairman & Chief Executive Officer
Thanks.
Operator
And we'll take our next question from Doug Leggate from Bank of America. Please go ahead.
Doug Leggate - Bank of America Merrill Lynch
Thanks. Good morning, everybody.
Scott D. Sheffield - Chairman & Chief Executive Officer
Doug.
Doug Leggate - Bank of America Merrill Lynch
Tim and Scott, I wonder if I could just pick up on a couple of the questions that have been asked so far. So on the 15% growth target, just to be clear, what are you assuming as your sort of standard well design to get to that number?
I'm just kind of trying to figure out, is that an outcome, or is that the target, because there's obviously a lot of flexibility as to how you get there, but in terms of type curve and lateral lengths, what are you assuming in that 15% target?
Timothy L. Dove - President, Chief Operating Officer & Director
Well, so far what we're assuming is type curves that are roughly the million barrel type curves, Doug. And when you take a look at the lateral lengths, it's going to correspond to – that would correspond to the typical 8,500-foot lateral.
So to the extent we're 9,500, it would be a type curve slightly higher than that, so it might be 1.1 million BOE or something like that for a 10,000-footer or a 9,000-footer. So I think you have to look at this and say that will be built in, but all the efficiency gains would not be.
Doug Leggate - Bank of America Merrill Lynch
So, Tim, in the event, then, that – let's assume that the type curve, as you pointed out, you might revisit that next year, let's assume it comes in better and the laterals end up in longer. Do you adjust your activity level down to cap your growth at 15%, or what – how do you respond if that turns out to be the case?
Timothy L. Dove - President, Chief Operating Officer & Director
Well, the first thing we're focused on, as Scott has already mentioned, is returns. Let's go on the basis that returns are strong.
We would take a look at the combination of levers we have and make a decision about that going forward. As you can tell, we are sort of focused on trying to maintain a CAGR growth rate that makes sense in the face of those returns, but we can land our growth rate essentially on any number we want to depending how much money we spend.
We can spend less money if we have these efficiencies and achieve the same results. So this is going to be, I would say, kind of a moving target.
We have a goal set at the 15%-plus CAGR rate. We could exceed that if we choose.
If we were in a lousy commodity price environment, we could come in under that if we wanted to. So it's more or less a general target, and it will be adjusted to the extent of the number of dollars needed to be spent would be substantially lower to the extent these efficiencies and productivity numbers continue.
Doug Leggate - Bank of America Merrill Lynch
I know it's an unfair question, Tim, but I guess you've kind of drawn it out by your comment here. Why is 15% the right number when oil's 45 bucks?
Timothy L. Dove - President, Chief Operating Officer & Director
Well, I don't know that 15% is the right number or the wrong number, it's just a target we have internally for the type of growth rate we think we can achieve when the economics are as strong as they are.
Doug Leggate - Bank of America Merrill Lynch
Okay. My last one is just picking up on your comment about the Wolfcamp A's.
So I just want to try and understand, is this going back to existing pads, or is it – when you think about going back to – if you skewed toward the A's next year, and if so what are the implications for infrastructure spending? And I'll leave it there.
Thanks.
Timothy L. Dove - President, Chief Operating Officer & Director
Yeah, in principle, a lot of these A's are following localized B's, as I mentioned, because we believe the right thing to do is come back to the A's from the standpoint of our modeling. You still have some areas where we – obviously building new pads; on a per-well connection base, as I mentioned, it'll be less next year.
We still have other areas, as I said, that we're drilling B wells that are going to need new infrastructure as well. So, yeah, I think the areas where you come back to existing pads, you're obviously not going to need as much capital, but we're still building new pads as we speak.
Doug Leggate - Bank of America Merrill Lynch
So in a lot of that population next year, then, is it fair to assume that tank batteries and so on are already in place?
Timothy L. Dove - President, Chief Operating Officer & Director
Yeah, for some of the campaign, it certainly are. For others they are not.
Doug Leggate - Bank of America Merrill Lynch
All right, I'll leave it there. Thanks, guys.
Scott D. Sheffield - Chairman & Chief Executive Officer
Hey, Doug, one last item. On the $45, you got to realize we do not believe that we're going to have $45 flat for the next three years.
So we're targeting 15% growth over the next three years on the strip price case. And I don't think anybody here thinks we're going to be $45 for the next three years.
If we did, we would not be targeting a 15% growth rate – let me say that.
Timothy L. Dove - President, Chief Operating Officer & Director
And I'd embellish that sentence by saying we're looking at margins, Doug, not the commodity price per se. We're looking at what our economics are pursuant to the margins.
Operator
Okay. And we'll take our next question from Brian Singer from Goldman Sachs.
Please go ahead.
Brian A. Singer - Goldman Sachs & Co.
Thank you. Good morning.
Scott D. Sheffield - Chairman & Chief Executive Officer
Good morning, Brian.
Brian A. Singer - Goldman Sachs & Co.
Wanted to focus first on production mix. Can you talk to how we should look at the path to moving to your 60% oil objective?
And specifically within the Permian, we haven't really seen that much movement here in the last few quarters – increases, that is – despite now a multi-quarter focus on horizontal drilling. What is the right percent oil in the Permian and the timing and catalyst to get there?
Scott D. Sheffield - Chairman & Chief Executive Officer
Yeah, Brian, it's – I mean, as you saw, the well mix was 78% oil. So as we add more Lower Spraberry Shales, they're up in the 80%s.
You look at our peers, they're up in the 80%, 85% range, so it's a combination of what we're seeing the mix of Wolfcamp B, Wolfcamp A's, and the Lower Spraberry Shales. And so it's a slow movement from 52% to 60%, but it's what we're seeing in the model.
As we add the results from the eight additional rigs that you're starting to see in the late first quarter and second quarter next year, you'll see that mix even increase even more so going into second half of next year.
Richard P. Dealy - Chief Financial Officer & Executive Vice President
Brian, the other thing you're seeing, too, is you're seeing improved gas recoveries and NGL recoveries now that Targa has taken over and optimized the systems out there. They've made a lot of improvements.
So we're getting better gas recoveries than we were getting before.
Scott D. Sheffield - Chairman & Chief Executive Officer
Which affects this year.
Richard P. Dealy - Chief Financial Officer & Executive Vice President
Yeah, affects this year in particular.
Brian A. Singer - Goldman Sachs & Co.
And that would also positively impact, then, reserves EURs recovery rate, or is that not the case?
Scott D. Sheffield - Chairman & Chief Executive Officer
Yes, it does, in a sense, because you're holding – the lines that we're putting in place are increasing the size of the lines, so it allows you to get more recoveries over time.
Brian A. Singer - Goldman Sachs & Co.
Okay, great. And then a bit of a follow-up to some of Doug's questions earlier on.
On your capital budget and growth plans, how does the oil price environment play into the equation? When you talked about 2016, you're very well hedged, strong balance sheet, you talked about having flexibility to change that growth rate around and the rig count around depending on whether you have bad oil prices versus good oil prices.
What is it that governs your decision on whether to increase the drilling and completion cadence in 2016 versus stay flat at your year-end 2015 levels?
Scott D. Sheffield - Chairman & Chief Executive Officer
We've already – we haven't really changed our plans in 2015. Just to remind you, we've seen $38 once.
We saw $42. We saw two lows.
But as long as Goldman keeps putting – if you all stop putting out $20 stuff, it would help, but I'm hoping that we do not see $20. But I think we're at a bottom.
And oil prices are going to move up second half of 2016, and we'll be $60 in 2017 or higher. You'll see us add more rigs if we see that event happen.
But, remember, if for some reason we do go to $20, in that scenario we get $20 plus, and we're only collecting $40. And if it stays at $20, we're obviously going to cut back rigs.
So – but if it stays like it has in 2015, I do not see making any changes in 2016.
Brian A. Singer - Goldman Sachs & Co.
And so I guess just to follow up, then, is it a balance sheet constraint, where you're trying to get to a net debt to EBITDA type number? Is it a CapEx cash flow balance?
What is it that you look at to say we should increase the rig count versus not?
Scott D. Sheffield - Chairman & Chief Executive Officer
We have a tremendous inventory. Our number one driver is returns.
Second driver's bringing NAV forward. So those are the two drivers.
So it's important for us. We have so many locations.
Some people ask, are you depleting your inventory in this price environment? The answer is no, it's minuscule.
When you have a 100-year inventory, it's important to bring your NAV forward. The best way to do it is to put rigs to work.
The economics are good. That's the key driver.
So I don't think you're going to see us change in regard to what we've laid out for 2016 at this point in time.
Brian A. Singer - Goldman Sachs & Co.
Great. Thank you very much.
Operator
We'll take our next question from Stephen Richardson from Evercore. Please go ahead.
Stephen Richardson - Evercore Partners Inc.
Good morning. Was wondering if you could talk a little bit about acknowledging that you're just getting a lot of these efficiency gains, longer laterals, lower costs, and the implication of fewer rigs and fewer wells and the 15% uplift on the EURs, but how is this implicating your view on cash neutrality and the timing at which you think the program can reach kind of CapEx cash flow at – acknowledging kind of a – balance, acknowledging a normalized oil price at some reasonable level?
Is that part of this calculus, and is that point coming forward in time as you look at your corporate modeling?
Scott D. Sheffield - Chairman & Chief Executive Officer
Well, I think with us or with the industry in general, we've all – when you look at – we've all overspent cash flow. But it's been done – a lot of us have done it with asset divestitures in the past.
We've done it with joint ventures. We've done it with equity.
We've done it with higher debt levels. Certain companies have done it too high of debt levels, obviously, in this environment.
And so in a reasonable price environment – I think most people predict that we'll be back in a $60 to $80 price environment – under that price environment, we'll get to neutrality. Whether it's $60 or $70 depends on what happens to the service cost and efficiency gains.
We see actually getting to a point to where we'll be spending cash flow and growing substantially. I can't tell you what that is without several other factors and making assumptions.
Stephen Richardson - Evercore Partners Inc.
But, Scott, fair to assume that better wells, fewer wells to get to the 15% CAGR and efficiencies you're seeing across the program, that every one of those contributes to bringing forward that point in time, acknowledging that commodity price is important?
Scott D. Sheffield - Chairman & Chief Executive Officer
Exactly.
Stephen Richardson - Evercore Partners Inc.
Okay, and I guess that segues well into the second question, which is clearly the equity window has been open for you and some of the peer companies, particularly in the Basin. How do you think about – acknowledging you've got the other $500 million from the Eagle Ford sale coming next year, but how do you think about equity and your prioritization of funding the next couple of years as you look out?
Scott D. Sheffield - Chairman & Chief Executive Officer
Yeah, if you look at our growth rate and look at our balance sheet and our $500 million of cash flow coming in from enterprise and look at our hedge book, at this point in time we see no need, like some of the other companies have gone out to the marketplace. Those other companies that have done it recently, their balance sheets were more stretched.
They did not want to take any risk. At this current time, we see no reason to do anything at this point in time.
Stephen Richardson - Evercore Partners Inc.
Great. Thank you very much.
Operator
And we'll take our next question from Evan Calio from Morgan Stanley. Please go ahead.
Evan Calio - Morgan Stanley & Co. LLC
Hey, good morning, guys, and very good operational results today. My first question is really a kind of follow-up on some of these prior questions on the low rig count, and hopefully not beating a dead horse here, but are efficiency gains and well performance since just June, when you raised that guidance, the primary change to drive a different rig count outlook to deliver your growth profile, or is it more moderating your activity through the trough due to commodity considerations?
Timothy L. Dove - President, Chief Operating Officer & Director
I think if you look at the data that we provided, Evan – this is Tim – you can see that we've been staring at these efficiency gains for some time, and particularly if you look at slide 11, where we show the number of days on wells coming down. But the dramatic reductions we've seen really have been the last two quarters.
We've moved, if you look back at the slide, from 37 days to 25 days. That's pretty dramatic improvement right there.
We start seeing that, and we realize, wow, we really don't need as many rigs to be operating to achieve the same sort of results, and that's a linchpin, I think, on the one hand. On the other hand, we're seeing these dramatic improvements in productivity gains per well.
And cost savings as well. So we basically can spend less dollars, have less activity and get to the same answer.
So it really, I think, it's really dawned on us really over the last couple quarters as we've seen the confluence of all those factors, and that's led us to where we're landing the rig count today.
Evan Calio - Morgan Stanley & Co. LLC
Great, that's very clear. My second question is somewhat related, but a question on the completion designs in the quarter.
Almost 60% of the Permian completions were optimized with very strong results. I mean, can you discuss maybe the primary variable that's changing, such as stage spacing or stage size, and any indications that you've reached limits of optimal?
Or could we see the scope for continued rate of change into 2016? And that's not just from more wells being optimized as per your guidance, yet from a continued improvement of what optimized means?
Timothy L. Dove - President, Chief Operating Officer & Director
Yeah, I think, first of all, when we're talking about optimization, optimization is going to be a long-term project around here, because not every optimization concept will apply to each zone, and nor will it over long areas, wide areas – aerial extent of the field. And so – but you're right, I mean, the concepts come in the form of several.
One is just pump more volumes in terms of proppant, and the same would be true of fluid volumes. And, importantly, I think, changing the stage lengths, reducing the stage lengths, increasing the clusters per stage, we think is important as well.
What I can tell you is we're testing all these different parameters in different wells. So we're a long ways from being able to say, "Man, here's the concoction that makes the most sense across the whole field" and let's say, for example, Wolfcamp B, because we're just in the early stages testing one-off all these different concepts.
I mean, you have to use the scientific method here, where you statistically look at offset wells that were not completed with the new style versus the results from those that are completed with new techniques, and then come to a conclusion about what sort of net improvement you're looking at. So I would say we're early days.
I think we'll be continually improving, we'll be continually optimizing, and it's going to take a long time before we can say that this is definitive in certain areas that this is the way to do it. I think if you look at the – the perfect example is we haven't done any optimizations on Lower Spraberry Shale wells, zero.
So we're not even started there yet. And we've done it on two Wolfcamp A wells out of the whole mix.
And so we just have a lot more work to be done. But that's our job, is to basically, continually to improve and optimize.
Evan Calio - Morgan Stanley & Co. LLC
And that process is incremental, going incrementally tighter in different wells, for instance, on stage spacing, versus actually stepping to test a real theoretical limit. Is that accurate?
Timothy L. Dove - President, Chief Operating Officer & Director
Well, I think if you – there's only a certain distance you can shrink down to in terms of the distances between clusters. And so we're testing a pretty tight cluster space right now, which is I think about 60 feet between the clusters.
And so you also realize the more stages – the more clusters you have, the more you're actually having to increase your cost of completions, right? Because you're in there, if we're using a plug-and-perf method, we're drilling out more plugs, we're on the well a little bit longer from a completion standpoint.
And with that comes some risks also. So it's not just a situation where you can just drill an unlimited number and get down to – get down to, essentially, where the whole zone is fracked, or with clusters.
But I can see us moving down in some of our testing even to 30-feet cluster spacing. So we're doing that as well.
So it's really a combination of all those things, to try to basically improve.
Evan Calio - Morgan Stanley & Co. LLC
Very helpful, guys. Thank you.
Operator
And we'll take our next question from Michael Hall from Heikkinen Energy. Please go ahead.
Michael A. Hall - Heikkinen Energy Advisors
Thanks. Congrats again on a good update.
I just wanted to, I guess, dive in a little bit more on the efficiencies and the commentary around spud-to-POP, and how that relates to the pace of completions we've seen here in the second half of 2015. If I'm doing the math right, a 135-day spud-to-POP implies maybe 115 POPs on a 14-rig program for 2016 in the north.
But you're completing, call it, 33, 34 POPs per quarter here in the third and fourth quarter in the north. So if I run that out through 2016, I have over 130 completions.
Just trying to understand, I guess, how to think about completions pace per quarter and what sort of additional efficiencies might be potentially expected relative to the 135 spud-to-POP?
Timothy L. Dove - President, Chief Operating Officer & Director
Well, I think the way to think about this – and here I think of it in total, the totality of the Permian Basin – this year we're going to POP about 195 wells. I think along the lines of your math, I think our estimates would say us getting to 240 wells next year.
So your pace goes up roughly to the tune of 20%. So, if we were out there POP-ing let's just say on average 40, 50 wells per quarter, that goes up to maybe 60 or something like that.
So I think that's what you're going to see. But realizing first of all, we just reduced the amount of time when it comes to spud-to-POPs by about 30 days.
But even at 135 days, those wells that we began drilling in July and August are just now at the end of the year going to be popped, in the sense of a three-well pad. So you still have four and a half, five months between when you start up and when you're done.
Michael A. Hall - Heikkinen Energy Advisors
Okay. So – no, that's helpful.
240 wells give or take on a -
Timothy L. Dove - President, Chief Operating Officer & Director
North and south.
Michael A. Hall - Heikkinen Energy Advisors
Okay.
Timothy L. Dove - President, Chief Operating Officer & Director
Maybe – I think our math would say 175 in the north roughly.
Scott D. Sheffield - Chairman & Chief Executive Officer
Yeah.
Timothy L. Dove - President, Chief Operating Officer & Director
Balance in the south.
Michael A. Hall - Heikkinen Energy Advisors
And that's on a flat 18-rig program?
Timothy L. Dove - President, Chief Operating Officer & Director
Yeah, that's the current campaign.
Scott D. Sheffield - Chairman & Chief Executive Officer
Pretty much, yeah.
Michael A. Hall - Heikkinen Energy Advisors
Okay, that's helpful. And then I guess I was just trying to think about also then kind of just organizational readiness for that continued ramp up.
You're getting to pretty high quarterly POP rates. I mean, how are you all staffed on that front?
Are you fully built out and feel comfortable with that, or is there any additional adds that are needed in that context?
Timothy L. Dove - President, Chief Operating Officer & Director
Well, you may remember, in the mid part of 2014, we were running 26, I believe it was, horizontal rigs in the company.
Michael A. Hall - Heikkinen Energy Advisors
Yes.
Timothy L. Dove - President, Chief Operating Officer & Director
Today we're not even to that number, even with the additions we've made this summer. So...
Michael A. Hall - Heikkinen Energy Advisors
Still plenty of room.
Timothy L. Dove - President, Chief Operating Officer & Director
Yeah, so we're not even back to where we were, what's now a year and a half ago, in terms of total rig count and therefore POPs. So we have an organization that's ready to perform at a high level at this rate.
Michael A. Hall - Heikkinen Energy Advisors
Great. And then I guess just shift over to the Eagle Ford a little bit.
I appreciate there's quite a bit of uncertainty around that program following I guess the light quarter. But running a six-rig program, kind of old type curves, seems like it's reasonably conservative to suggest it would stay flat at 43 MBOE a day.
I'm just trying to understand kind of what you have baked in on that sort of commentary around go-forward type curves relative to recent experience.
Timothy L. Dove - President, Chief Operating Officer & Director
Yeah, if you look at the type curves we utilize out there, they generally range, let's say, from 1.1 million to 1.3 million BOE. And that's sort of somewhat – we would say maybe 1.3 million historically, if we shave that down just based on recent results...
Michael A. Hall - Heikkinen Energy Advisors
Okay.
Timothy L. Dove - President, Chief Operating Officer & Director
...you might use 1.1 million in the range, but maybe down 10%, 15%. But if you look at the math on that and look at the – the returns, first of all, are quite good even at that kind of EUR, but the second thing is if you take a look at how that – we're using six rigs and play it out from the standpoint of three well pads, you can see easily we can keep production basically flat.
By flat I mean it could be a percent up, percent down or a couple percent up or down, essentially flat if you do the math on that.
Michael A. Hall - Heikkinen Energy Advisors
Okay, fair enough. Actually, if I might jump back to the Midland Basin real quick.
What do you have – the northern program horizontal wells, what were they booked at, at year-end 2014? From the unproved reserves?
Timothy L. Dove - President, Chief Operating Officer & Director
You're talking about the new well bookings from a proved reserve standpoint?
Michael A. Hall - Heikkinen Energy Advisors
Yep.
Timothy L. Dove - President, Chief Operating Officer & Director
That's kind of a – well, first of all, there'd be an averaging concept associated with that, but the way to think about it is we're conservative about our bookings, especially in the first year.
Michael A. Hall - Heikkinen Energy Advisors
Okay.
Timothy L. Dove - President, Chief Operating Officer & Director
And so it's not unusual for us to be booking what we think is 50% or 60% of the EURs of the wells in year one, just because the objective is to be moving in terms of revisions upward versus downward. And so you'll see potentially positive technical revisions moving forward in that field, if that's our philosophy.
Michael A. Hall - Heikkinen Energy Advisors
Okay, that's helpful. Then last on my end was just on the infrastructure spend.
You guys talked – I think this year you've got in the northern program $275 million for infrastructure and land, talked about – about a $25 million incremental spend on the infrastructure. Any other incremental increases on that line item that we ought to bear in mind as we think about building out 2016?
Timothy L. Dove - President, Chief Operating Officer & Director
Yeah, I think there's always moving parts, but I think we've covered most of those on the slide number 15.
Michael A. Hall - Heikkinen Energy Advisors
Okay.
Timothy L. Dove - President, Chief Operating Officer & Director
Like, for example, this year and last year, we did a lot more in terms of buildings, which – we're essentially done with our buildings. This is mostly field buildings, of course, so that's a number coming down.
Of course we're spending a similar amount when it comes to our water systems and gas processing. But when you tally everything up, most of the numbers are there included on slide 15.
Michael A. Hall - Heikkinen Energy Advisors
Great. That's helpful.
Appreciate it.
Operator
We'll take our next question from Leo Mariani from RBC Capital. Please go ahead.
Leo Mariani - RBC Capital Markets LLC
Hey, guys, wanted to focus a little bit on the Eagle Ford here. It sounds like you guys have got six rigs out there, and you're kind of indicating production can kind of stay flat over the next handful of years at that same level.
Just trying to get a sense if that's more of a theoretical statement, or if we do see oil prices recover, whether or not you guys would go in and add rigs there, and obviously I recognize competing for capital against the Permian.
Timothy L. Dove - President, Chief Operating Officer & Director
The returns have always been good. We had nine rigs running out there last year.
So, yeah, in a higher commodity price environment, Eagle Ford would definitely be a place we'd look to add capital, because it does compete very favorably with the Permian, from that standpoint they are very prolific wells and very high rates of production in the early stages of the wells. That said, what's hurting the Eagle Ford today is the fact that we still produce a decent amount of gas with these wells and a decent amount of NGLs, particularly ethane.
And so, with ethane economics and natural gas prices having been where they've been, you can see that it's taken it a little bit on the chin. And so at the margin it's still very positive, but it has a lot of running room to the extent we get higher commodity prices.
Leo Mariani - RBC Capital Markets LLC
That's helpful, and I guess obviously good performance update in terms of the well results in the Wolfcamp here and the northern Midland Basin. Just wanted to get you all's thoughts on what you're seeing in terms of some longer-term production performance from the Lower Spraberry.
You obviously mentioned you want to increase percentage exposure there next year.
Timothy L. Dove - President, Chief Operating Officer & Director
Yeah, Lower Spraberry Shale still is really one of our most prolific zones. As you can see, we're not drilling very many wells in the Lower Spraberry Shale as we speak, or POP-ing them.
You'll see a higher percentage next year. But Lower Spraberry Shale calculates to have the most oil in place of any of the shales.
It's also shallower. And so it will take a bigger place in the campaign.
Of course, this year, we've been focused on efficiencies and cost reductions. And so we're focused on the zone that we've drilled the most wells in.
So by definition that's the Wolfcamp B. Next year, we'll be drilling some more – some Lower Spraberry Shales in significantly higher numbers.
Leo Mariani - RBC Capital Markets LLC
Okay. And I guess the last question on the rig charges here, obviously that's been happening for the last couple quarters.
You're forecasting some more stacked rig charges in the fourth quarter. Just trying to get a sense when those sort of start to go away, if that's in the first half of 2016 or what can you tell us about that?
Scott D. Sheffield - Chairman & Chief Executive Officer
Yeah, it's generally in the first half of 2016. You're correct.
Leo Mariani - RBC Capital Markets LLC
All right, thanks, guys.
Operator
And we'll take our final question from Neal Dingmann from SunTrust. Please go ahead.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Morning, guys. I'd say just two things.
Scott, I know you've hit a lot of things today. Just – I really wanted to just get more on your comment about bringing the NAV forward.
I guess in this environment today versus if we were – I agree with you – if we do hit that $65, $70 type environment, how do you think about bringing that forward? I mean, to me it seems like you're maybe not getting credit for all the different benches anyway, so I like what you're doing with the B's.
So I'd just like to hear your comment about what you guys think, either you or Tim, best way to bring the NAV forward, either in today's environment or if we have where we go to maybe $65, $70 environment.
Scott D. Sheffield - Chairman & Chief Executive Officer
Yeah, Neal, obviously, in a higher price environment, the first thing we'll do is add more rigs. That's the best way to bring it forward.
And also, as we've been out there talking with shareholders and potential shareholders, Tim and I and Frank have been very open that we'll always look at evaluating acreage opportunities in regard – we've done that before already in the Permian Basin, whether it's joint ventures or whether it's selling acreage as we did up in the far north of the Midland Basin. We'll continue to evaluate opportunities like that, too, as a funding mechanism, by bringing NAV forward also, so.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
That makes sense. And then, just lastly on that point, I know you guys are not actively looking to sell anything today, or nor obviously, with the inventory position you have, certainly don't need to buy anything.
But just do you see anything with the M&A environment – I mean, it seems like prices never really did dip much, and we've seen a lot of excellent prices, I guess, nothing too recent. Just anything you could comment about M&A activity around either your north or south there?
Scott D. Sheffield - Chairman & Chief Executive Officer
Yeah, I think most of it's been in the north. There've been probably four to five deals in the $30,000 to $40,000 per acre range.
I think the recent two deals everybody saw in The Wall Street Journal, a Chinese company came in and spent $1.3 billion. It was not state-owned.
So private company, Chinese company, came in and paid a high price in the $30,000 to $40,000 per acre. The rest of it's been by companies, smaller companies that are trading at a high multiple.
They can go to the equity markets and deleverage. So there's been about five deals, I think, so far this year in that $30,000 to $40,000 per acre, which shows it's still the most favored basin in the U.S., the Midland Basin.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
I agree with you. And, again, guys, thanks for all the color today.
Scott D. Sheffield - Chairman & Chief Executive Officer
Thanks.
Operator
And now I'd like to turn the call back over to Scott Sheffield for closing remarks.
Scott D. Sheffield - Chairman & Chief Executive Officer
Again, thank everybody for participating, great questions. Looking forward to another great quarter when we come out in February.
Again, everybody have a great holiday and happy New Year if we don't see you on the road. Again, thanks.
Operator
And that does conclude your teleconference for today. Thank you for your participation.
You may disconnect at any time.