Pioneer Natural Resources Co. (PXD) CEO Scott Sheffield on Q1 2016 Results - Earnings Call Transcript

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Pioneer Natural Resources Co. (NYSE:PXD)

Q1 2016 Earnings Conference Call

April 26, 2016 10:00 AM ET

Executives

Scott Sheffield – Chairman and Chief Executive Officer;

Timothy Dove – President and Chief Operating Officer

Richard Dealy – Executive Vice President and Chief Financial Officer

Frank Hopkins – Senior Vice President Investor Relations

Analysts

John Freeman – Raymond James

David Kistler – Simmons and Company

Arun Jayaram – JPMorgan

Doug Leggate – Bank of America

Neal Dingmann – SunTrust

Charles Meade – Johnson Rice

Scott Hanold – RBC Capital

Evan Calio – Morgan Stanley

Ryan Todd – Deutsche Bank

Brian Singer – Goldman Sachs

Operator

Welcome to the Pioneer Natural Resources First 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 Investor Relations.

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.pxd.com. Again, the Internet site to access the slides related to today's call is www.pxd.com. At the website, select Investors then select Earnings and Webcasts. This call is being recorded a replay of the call will be archived on the Internet site through May 20.

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. The statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's news release on page two of the slide presentation and in Pioneer's public filings made with the Securities and Exchange Commission.

At this time, for opening remarks I would like to turn the call over to Pioneer's Senior Vice President of Investor Relations, Frank Hopkins. Please go ahead, sir.

Frank Hopkins

Good day, everyone, and thank you for joining us. I'm going to briefly review the agenda for today's call. Scott will be the first speaker. He'll provide the financial and operating highlights for the first quarter of 2016. Another quarter which saw the company deliver solid execution and outstanding performance. Scott will then review our latest plans for 2016 in the face of continuing commodity price uncertainty. After Scott concludes his remarks, Tim will review our continuing strong horizontal well results and capital efficiency improvements in the Spraberry Wolfcamp. Rick will then cover the first quarter financials and provide guidance for the second quarter of 2016. And after that, we'll open up the call as always for your questions.

So Scott, I'll turn the call over to you.

Scott Sheffield

Thank you, Frank. Good morning. Slide number three financial and operating highlights. We had a first-quarter adjusted loss of $104 million or $0.64 per diluted share. What's more important is that the company hit record production again first quarter of 2016, 222,000 barrels of oil equivalent per day, 55% oil. So we're well along on our movement from 52% to 56% oil from 2015 to 2016. Way above Pioneer's guidance range of 211,000 barrels per day equivalent to 216, an increase of 7000 barrels per day equivalent or 3% versus the fourth quarter of 2015.

Oil production is up 10,000 barrels of oil per day or 9% versus the fourth quarter of 2015. Obviously driven by the growth of the Spraberry Wolfcamp horizontal drilling program. What's also a milestone for the company by gross production in the Spraberry Wolfcamp fields exceeded 200,000 barrels a day equivalent for the first time and total field production has exceeded and surpassed 1 million barrels of oils equivalent per day and still growing. Probably the only field growing in today's environment in North America.

We placed 55 horizontal wells on production in the Spraberry Wolfcamp field during the first quarter. All wells benefited from completion optimization, which Tim will give you a lot more detail. Continuing to realize significant capital efficiency gains in the field, both with the optimization program, longer lateral lengths, increasing and enhancing well productivity. Drilling and completion efficiencies and cost reduction initiatives are still driving down a cost per lateral foot.

What's also more important, again, reducing our combined production costs and G&A expense for the quarter versus fourth quarter of 15%. We continue over the next several quarters to see continued improvement in regard to those numbers.

We also added the recently target operated Spraberry Wolfcamp gas processing plant of 200 million per day. It's online and essentially it's up to about 120 million a day and that came from other plants which reduced their intake and in those other plants, so there's plenty of room for the next two or three years for additional capacity. Pioneer just reminds people we do own 27% of this system.

Increased Oil & Gas derivative coverage for 2017. We've already released these numbers and we'll talk a bit more about it and moving our hedges up primarily 50% for 2017.

Slide number four, on our outlook. We plan to maintain our 12 horizontal rigs in the North Spraberry Wolfcamp field based on favorable returns in the area. We are currently operating 12 horizontal rigs in the North and two in the South and the two in the South will be terminated by the end of June. As I had mentioned on previous calls, our partner Sinochem will look more at a $50 oil price to reinitiate any rig activity at that point in time. This activity level is expected to deliver production growth at 12% plus, which we have raised up from 10% plus in 2016 and will allow the company to progress its completion optimization program. The higher forecasted growth rate reflects the improving Spraberry Wolfcamp well productivity.

We are keeping our planned capital expenditures the same for both drilling activity and vertical integration spending at $2 billion for 2016, $1.5 billion for drilling and $150 million for vertical integration systems upgrades and field facilities.

We get asked all the time, we put the comment in here, but Pioneer expects to add five to ten horizontal rigs when the price of oil recovers to $50 a barrel and the outlook for oil supply demand fundamentals is positive. So what do we mean by this? I mean, what's ideal? The strip in 17 has moved up to about $47, $47.50 for oil. Today's price is close to $44. So if we see the strip in 17, for instance, get up to $50, and we see inventory start to decrease which gives confidence in the supply-demand fundamentals, we know the supply side is dropping, the U.S. should see a significant drop in the third quarter on U.S. shale, probably a good 400,000 or 500,000 barrels per day in the third quarter, especially as reported by the EIA. And so what's ideal? We don't want to add them all at the same time. We would like to add a few at a time. So I know Frank gets asked the questions a lot, so that gives you a little bit more flavor and detail.

Going to slide number 5, on our hedge position. Obviously we're almost fully hedged for 2016. For oil we moved our hedges up from 20% to 50% for 2017. The detailed hedges are in the back. We would like to also continue to move that number up in 2017 over time as we see the oil price continue to move up in 2017.

We did a little bit more gas hedging for 2017. It's up to about 25%, still about 70% for 2016. That leaves us very strong investment-grade balance sheet. I think we're one of only six or seven companies that Moody rates investment-grade now. The forecasted cash flow enables the company to grow production and fund its expected capital program through 2017 without increasing debt. Our cash on hand liquid investments at $2.5 billion in the first quarter includes proceeds from the successful equity offering in early January. Also includes $940 million that'll fund the July 16 and March 17 senior note maturities. An additional half billion dollars will come in July 2016 from our Eagle Ford midstream sale business that we did in 2015. Pro forma net debt to 2016 operating cash flow of 0.4. At the end of the first quarter we had a debt to book of 10%.

Going to slide six. No change in our capital program. I think the only change on this slide is the fact that star had – the star is moving around on the rainbow chart. It's up to $1.4 billion. If the strip holds the rest of the year it'll be up closer to $1.5 billion. So that gives us an extra $100 million to $200 million of cash that'll be added into our coffers by the end of 2016.

Slide number seven. Obviously again reminding people we did increase our production growth forecast from 10% plus to 12% plus. So that takes us up to 229,000 barrels a day equivalent for 2016. Still keeping oil at 56%, up from 52% due to our well productivity in the Spraberry Wolfcamp. Our oil growth has gone up from 20% to 24% plus. Again, expect continued production growth over the 16/18 period. Obviously it'll depend on the pace of the commodity price recovery.

I'll now turn it over to Tim to get into more detail on our optimization program.

Timothy Dove

Thanks, Scott. I'll turn now to slide eight and I think it's safe to say our completion optimization campaign in the northern part of the Spraberry Wolfcamp continues to show very impressive results. Toward that end, I'd point you to the graph on the top left. This is a Wolfcamp B graph which shows all of the wells that have been completed utilizing our optimization campaign since the mid-part of last year, mid-2015. That's a total of 68 wells. What you see in the blue curve is an average of all of those wells in terms of its early production and you can see it's pretty clear that blue line far exceeds the million barrel BOE Type Curve shown below. In fact, we would calculate that the early production range would show about a 35% improvement compared to that curve. So that's obviously extremely positive from the standpoint of our completion testing.

And then if you look to the top right, the Wolfcamp A, we see similar results although realizing it's a substantial smaller sample size, with only 13 wells at the mid-part of last year. I think it's really too early to call what the ultimate uplift will be for the Wolfcamp A, but for the time being the chart would easily show a 20% improvement compared to the Million Barrel Type Curve. Lower Spraberry shale, again, a relatively smaller sample size, 16 wells in the same timeframe.

Early results again but we are showing improvement. We calculate this more about 10% over the Million Barrel Type Curve currently. But suffice it to say, on the 97 wells that we have performed completion optimization on through the end of the first quarter, we see significant improvement. Forty-two of those wells of the 97 that is, were placed on production in the first quarter and have seen similar productivity gains as had been the case in the prior couple of quarters. And now it's the case that these 97 wells provide a baseline for further testing that we're doing in 2016. And I'll talk more about that in a couple of slides.

On slide nine, we see similar results in the southern Wolfcamp area from the standpoint of the completion optimization, where we've tested about 22 wells through the end of the first quarter. You can see in the graph on the left the effects of the Wolfcamp B again, in this case about a 25% improvement over that Million Barrel Type Curve on 21 wells since the fourth quarter last year. And then similarly on the Wolfcamp A an improvement of about 25%, in this case above the 800,000 BOE Type Curve which we tend to see in the South. Of course, that's only one well in the Wolfcamp A on the bottom right graph but nonetheless, it's also encouraging.

Turning now to slide 10, this is the slide in which we show a little bit more detail on how these completion designs have adjusted through time. If you look at the left-hand part of the slide, you see our basic initial design of fracs during the period of 2013/2014, which is early days in terms of the play, and it generally had us with probably no more than 1000 pounds of sand per foot, 30 pounds – sorry, 30 barrels per foot of fluids, 60 foot cluster spacing, 240 foot stage spacing. And the idea there was long half-length fracs was the initial design concept to reach out and touch rock far away from the well bore.

As we move forward into 2015, the second half of 2015 to the first quarter, we've now put these 97 wells on production in the North, 22 in the South. It's the subject of really more of the same, which is 1400 pounds. You can see on this graph 36 barrels of fluid and so on, tighter cluster spacing. Of course, that does cost money. That's what gets us to about the $7.5 million to $8 million well cost based on 9000 foot lateral, the additional 500,000 coming from this frac design.

But in essence, the frac design that we put in place and we now see the results for becomes the new standard design and really the new base case that we're testing the further optimization techniques that we're employing this year. We're going to see more results as we go. There's an 80-well campaign underway to really substantially increase the profit utilization in some cases up to 2000 pounds per foot and in some cases over 50 barrels per foot of fluid and even down to 15-foot cluster spacing.

And so we really are pushing the design envelope right now to hopefully be able to reach some sort of optimal stage here by the end of this year in terms of how to complete these wells at least from the standpoint of utilization of current technology. And the additional amount of fluid and profit and so on does add about $500,000 to $1 million per well and I think it's – we believe the optimization actually will have a positive payout but stay tuned on that because we won't see much data on this until we get into the second through the fourth quarters. As you can see, just depicted from a cartoon standpoint, what we are trying to do is now design completions to allow more rock near the well bore to be contacted. It also will allow us theoretically to more tightly space the wells and optimize recoveries.

So I think this is an action that we have been planning on for some time. We have this well underway as we speak and hope to see some positive results going forward. We'll certainly know much more in the next few quarters. This is really one of the critical reasons that we mentioned in regard to maintaining our 12-rig campaign because we really need to continue our further understanding of this completion optimization business so that we're ready when we accelerate our drilling campaign when things improve in terms of commodities to do so in an optimal fashion.

Turning now to slide 11. Another area where we've been successful in adding value is extending laterals in this case beyond 10,000 feet. We placed a couple of our longest laterals on production in the first quarter, 11,000 and 13,000 feet of perforations, each of which was the subject of completion optimization. Of course, those wells being longer laterals, adding roughly $10 million each. Early data looks very encouraging. As shown here on the graph on the bottom you see in the green line the two most recent wells, the longer lateral wells, as compared to wells that were drilled prior to those which had shorter laterals.

So in the case of the 23 wells you see on the blue curve, you see below that 13 wells which are on the grey curve. It's pretty clear to see that the longer laterals are in fact contributing really substantial improvements over the earlier predecessors which were more like 9500 foot laterals and 7000 foot laterals. So I think it's pretty clear we continue to see a very strong correlation between lateral length, perforated lateral length and well productivity and we continue to see that as we look forward.

I would say we'd do the calculations over 60% or so of our acreage is amenable to base on the lease hold configurations over 10,000 foot lateral drilling.

Turning now to slide 12. This is an update essentially from a slide that we shared with you last quarter. It shows now a 32% decrease from year end 2014 until the first quarter in terms of our drilling and completion costs per foot. We still are at a point where we think we can reduce this going forward. The easiest way to explain it is we still are under old drilling contracts with very high day rates in the mid-20s where today's rates are probably more in the mid-teens.

So we continue, as those contracts roll off, to see reductions, not considering the fact we're also going to be continuing to try to optimize regarding completions and one of the major areas where we see cost reduction opportunities has been in our frac fleet efficiency where we really measure that in terms of the number of feet that are completed per day by each fleet and in this case we've seen the average Pioneer pumping services fleet increased substantially from about 800 feet per day of lateral section completed to about 1200 feet per day during the first quarter. That translates directly into speed of the job as well as an addition the cost reductions that come from time. And really what it amounts to is we're getting more wells popped faster and that's simply another component of outperformance when it comes to production. And it certainly, of course further helps to reduce costs and improve our overall drilling economics.

Turning now to slide 13. Activity continues to be focused on the north where our plans are essentially unchanged from where we were last quarter and Scott mentioned the fact we'll be drilling with the 12 rigs in the North with about 230 wells to be on production. Our mix of wells still is predominantly Wolfcamp B and Wolfcamp A. The mix essentially remains the same. What was now the – prior of course the standard completion technique is now subject to the new optimization campaign I mentioned earlier and if we look at this from the standpoint of the 2015 optimization campaign, we're still in that $7.5 million to $8 million cost per well assuming 9000 foot laterals. In addition to which to the extent the optimization is completed on those wells in the new style of optimization we had on our $500,000 or $1 million per well.

One advantage we have in this field is a tremendous opportunity presented by low LOE. Because these are very high volume wells and they typically run $3 to $5 per BOE in terms of at least operating expense. When you add taxes on you have a very favorable $5 to $7 total cost to operate these wells and that's one of the reasons you'll – Rich will comment on this, but you continue to see our LOE per BOE reduce through time is simply because as we add more of these horizontal wells into the mix it just drives down our averages in terms of LOE.

The economics still look good. I think they're still conducive to our drilling activity and certainly with regard to where prices are today, would exceed 30% IRR. It's probably in the neighborhood of approaching 40%. And it also, of course, allows us to progress our completion optimization campaign and be ready to optimally move ahead when we think we get the price messages to accelerate drilling.

And then on slide 14, the outstanding well performance I've been talking about in the Spraberry Wolfcamp area is driving strong growth and actually with production exceeding our forecast once again, it has led us in this field to increase our guidance for the rest of the year and actually, the total year now is 167,000 BOE compared to an earlier forecast of 162. First quarter production was very strong. Scott has already touched on a lot of these numbers but in this field particularly we had 149,000 BOE per day, almost 70% oil and increased about 9% since the fourth quarter of last year. We did put the 55 wells on production this quarter; 42 in the north, 13 in the South. And you can see on this slide the mix of wells. Again, it's very similar to the mix of campaign of 2016 in total which is predominance on A/B wells. Once again, production in the quarter benefited from the completion optimization longer laterals pop timing due to efficiency gains and everything we've been talking about in the prior slides.

Looking forward, we are increasing the growth rate of the field to about 33% this year. It had been at 30. Again, just reflecting on these productivity gains and we will be popping estimated about 60 wells in the second quarter, that compares to 55 in the first quarter. We are utilizing choke management in some areas and what that leads to is a situation where 24-hour IP rates and even in some cases 30-day IP rates can really have less meaning when we are optimizing the use of the infrastructure in the area without overbuilding water capacity for peak production. What we're doing, of course, is we're pumping with more fluid.

We're also just by choice completing more wells near existing infrastructure and what that has the effect of doing is filling up our water handling capacity so what we do is we choke the wells back typically for a couple of weeks, can be two to four weeks, in order to basically allow them to produce and not overfill those facilities and at which point in time we would basically full produce the wells. But again, as I said, one of the main aspects of this to consider is I think it's the right economic decision but at the same time it will cause IP rates in some cases to appear a bit odd because of the curtailment of the wells in certain areas. I think we'll see a little bit less of this going into the next quarter simply because where we're choosing to complete the wells in the quarter.

So overall, I'd say it's a stellar quarter for the company from an operational standpoint and it sure sets us up well for a strong 2016 from a standpoint of full-year results.

And with that, I'm going to pass it too Rich for his review of the financials for the quarter and also his outlook for the second quarter.

Richard Dealy

Thanks, Tim. I'm going to start on slide 15. We reported a net loss attributable to common stockholders of $267 million after-tax or $1.65 per diluted share. That did include noncash mark-to-market losses of $111 million after-tax or $0.69. And then you can see on the slide here included unusual items, aggregating a $52 million loss or $0.32 per diluted share principally related to impairments, one on the West Panhandle field and one in Alaska where we held a royalty interest and some unproved acreage. Those were mainly due to lower commodity prices at the end of March.

We also took a charge of $10 million associated with the early termination of 10 drilling rig contracts that we're not going to use prior to their exploration and so that was just a cost-saving decision to do that. So after adjusting for the unusual items that Scott mentioned, we are at $140 million loss or $0.64, principally attributable to the lower commodity price environment that we're dealing with.

If you look at the bottom of slide 15, we show Q1 guidance versus results. Scott talked about the outperformance on production. And then if you look at really the rest of the items, they were either on the positive side of guidance or within guidance throughout there, so I won't go through each in detail, just to say that it was a really good quarter. The company's cost structure continues to come down and so other than the backdrop of commodity prices, really excellent results.

Turning to slide 16, looking at price realizations in more detail. As you guys all know, it was a tough quarter on pricing. Oil prices for the company were down 26% to $28.09. NGLs were down 15% to $10.33 per barrel and gas prices were down 12% to $1.79. Fortunately for the company we were well hedged and so we were mitigated by our derivative portfolio rate, running about $217 million of incremental cash flow from our derivatives. Hopefully the first quarter was the low point as commodity prices have strengthened some in the second quarter and so hopefully we've seen the bottom and future quarters will show better realizations.

The one other item I'd point out at the bottom on our NYEMX differential for oil for the first quarter, you can see it was up a little over a dollar that differential. That's predominantly due to Eagle Ford condensate sales. In the last year, if you recall, we were exporting about 20,000 gross barrels per day of condensate. That contract expired at the end of the year and so we had a few minor spot sales in the first quarter but principally got domestic pricing and so that caused our differential to go back up. We do have or expect to see improved pricing in the second quarter with improved domestic pricing under new contract.

Turning to slide 17 and production costs. All of the asset teams, as Tim talked about, have really done a great job on working to lower their cost structure and improve our margins. You can see that production costs were down 17% in total from Q4 to Q1. Base LOE was down 20% quarter-on-quarter, principally related to lower costs on chemicals, electricity, contract services and just efficiency improvements that the operations guys are doing to really help with margins. So overall, production costs continue to trend lower and plus as Tim mentioned, we are adding more horizontal wells to the mix of wells with an average of %$5 to $7 per BOE of production cost which will help continue to drive these costs down.

Turning to slide 18, the company's balance sheet, we have excellent liquidity with net debt at the end of the quarter $1.1 billion. That's net of cash on hand in our liquid investments about $2.5 billion. We're still expecting to get the $500 million in July from our Eagle Ford midstream business sale that we did last year that'll come in July. Undrawn credit facility of $1.5 billion is still completely unused. As you're aware, we have pre-funded our 2016 and 2017 bond maturities and so that's in the $2.5 billion of cash on hand and so no near-term maturities. We've got that all taken care of.

And during the last 60 days or so we have been affirmed by Moody's, S&P and Fitch, so obviously recognizing the company's strength of our balance sheet. So overall, I'd say excellent balance sheet, well-positioned to increase activity levels when oil prices improve, as Scott and Tim both talked about.

Turning to slide 19 and switching gears to second-quarter guidance, we are forecasting production of 224,000 to 229,000 BOE per day for the quarter. The rest of the items here are really consistent with first-quarter results, so rather than going through each of those in detail, I'll let you read through those. But consistent with what you would've saw from first-quarter actual results.

So with that, why don't we stop there and we'll open up the call for questions.

Question-and-Answer Session

Operator

Thank you. [Operator Instructions] We'll take our first question from John Freeman with Raymond James. Your line is open.

John Freeman

Good morning, guys. Terrific quarter.

Scott Sheffield

Thanks, John.

John Freeman

First question I had, obviously given a lot of the efficiency gains, Tim, that you talked about, you brought online significantly more wells than you originally expected in the Spraberry Wolfcamp in the first quarter, but yet the full-year guide still says to expect the same 230 wells on production. So maybe if you could just speak to is there any reason to expect those efficiency gains to not continue?

Scott Sheffield

Yeah, John, I'd say first of all, we did, because of the efficiency, complete a few wells, really a handful, probably ten more wells than we had planned in the quarter. Most of those were near the very end of the quarter as you might expect, just the way the timing works and so they don't have much of an effect on the first-quarter results as they will have more of an effect in the second quarter. But as to the bigger picture, I think we're going to see continuous optimization gains across the board. It has to do with all the things I mentioned regarding the completion optimization campaign on the one hand but also mixing in longer laterals. We're going to have 10 to 20 long lateral wells here in the mix for 2016 as well. So I think it's going to be more of an all of the above. I think you're going to see continuous gains and I think you'll see us hopefully continue to outperform.

John Freeman

Okay. And then just last question for me. On the two wells that you did that averaged about the 12,000 foot lateral, I just wanted to verify that the only difference between those wells and the others on that slide 11 is just the lateral length? They didn't benefit from this, I guess for lack of a better version, the 3.0 optimization plan that you're going to do on these 80 wells? Like, that was just straight lateral length longer versus the others?

Scott Sheffield

Yeah, essentially that's correct if you saw what I mentioned in there, it was the, what we now call the baseline optimization, not the 2016 version which we compare them exactly with all the rest of the wells that were drilled prior.

John Freeman

Perfect. Great quarter, guys. Thanks.

Scott Sheffield

Thanks, John.

Operator

Thank you. And we'll move next to Dave Kistler with Simmons and Company. Your line is open.

David Kistler

Good morning, guys. Great work. Looking at the increased production or the impressive production beat that you guys delivered and kind of building on the last question, can you break down a little bit of what the benefit was of weather versus additional completions versus well productivity in terms of what drove that beat? I'm guessing from the answer you gave previously, it's primarily well productivity versus additional wells popped, but any added color you can give on that would be helpful.

Scott Sheffield

Okay, Dave. Yeah, the weather was not a factor. We were fortunate this year as compared to – you recall some of our prior years with ice storms and gosh, who knows what? We were really hammered two out of the last three years, but this year we got lucky and had good weather. So it was not whether and I already mention the fact that we had let's say ten additional completions. Really it's semi-immaterial for the first quarter because they were late in the quarter. So it has all to do with well productivity and this has to do with the fact that the graphs I showed really depict the fact that we're producing better wells and better initial rates. And when you have better initial rates than what you had planned in the forecast, then you're going to exceed and that's what's happening.

David Kistler

Great. So the way to view that is definitely much more secular in nature, not just a temporal item?

Scott Sheffield

I think we're going to continue to improve is what I'd say.

David Kistler

And then following up also, last quarter you guided to shut-ins as a result of fracking offsetting wells. When you guys kind of think about that going forward, will there be a continued impact from fracking offsetting wells? Or should we actually look towards maybe even a slightly larger uptick associated with not doing that going forward?

Scott Sheffield

So the way to think about that is we did in fact shut in almost exactly the number of wells and barrels that we had planned in the first quarter substantially more than we had shut in in the fourth quarter. So despite that, our production exceeded. That said, I think our second-quarter numbers look lower in terms of shut in offset production. It's just simply a matter of the mix of wells and where they're being drilled and completed. It just so happens in the second quarter we haven't got as many offset issues as we had where the wells were chosen for the first quarter. So I would anticipate that number to come down somewhat.

David Kistler

Okay. Appreciate that. And then one last one. When you talk about adding incremental rigs, kind of five to ten, and staging them in, can you talk a little bit about how you sit with respect to personnel to handle that ramp up and maybe specifically with the tool pusher and the effective driller on each one of those rigs?

Scott Sheffield

We've actually had the good fortune of hanging around with some of our drilling contractors the last few days and they are ready to add rigs and they're getting pinged upon right now by industry, as you might expect, to start potentially adding rigs. And they would make the case that if you were talking about a handful of rigs like we are, let's just say five to ten rigs, that's no problem at all. It's when we start to have a major acceleration where they would have issues because what they've done, of course, is to keep most of their management and supervisory personnel. They don't have to really rebuild staff. There's quite a few people who are available to come back to work, it's just a matter of making that happen.

So I don't think a small number of rigs that we're really talking about today is that material of an issue. As for us, of course, we have this advantage that's associated with having Pioneer pumping services, Pioneer well services. We have our own people ready to go complete our own wells and work on our own wells. And so we won't miss a beat and I think our drilling contractors will be there with us in good shape at least for this first tranche.

David Kistler

Great. Well, I appreciate the added color. Fantastic work, guys.

Operator

Thank you. We'll move next to Arun Jayaram from JPMorgan. Your line is open.

Arun Jayaram

Yeah, good morning, gentlemen. I wanted to talk a little bit – or ask you a little bit about the new guidance. You raised your overall guidance by 2% and oil by 4%. And I'm just trying to understand the magnitude of well productivity gains that you've assumed in your new guidance because it is the same number of wells. You guys have talked about seeing 10% to 35% improvements in well productivity but what is it in the new guidance?

Richard Dealy

Arun, basically what we've done is we pushed up some of the productivity, if you want to call them EURs internally, on wells in certain areas based on results that we've seen now not only for the first quarter but the past two quarters. I get the question all the time, when are we going to raise our Type Curve and the answer is give us a couple of more quarters. Let us get some more data. I think you've heard Tim and Scott say that we think we'll have a pretty good understanding of the Wolfcamp B by the end of this year or we'll certainly be in a position to do that. Wolfcamp A lower Spraberry shale, it might take into next year just because of the timing again of getting an update. We're trying to not get too far out in front of this but we also recognize that we do have to provide you with some reasonable estimates of where production is going to go based on our actual results.

Arun Jayaram

Okay. That's helpful. That's helpful. Just a second question perhaps Tim, in terms of lateral lengths. You've been drilling wells kind of in the 8200 and 9200 foot range. You've obviously announced some results on the wells beyond 10,000 foot. Have you had any conclusions on what you think the optimal lateral foot could be in terms of drilling and some of the wells in the shale ranch? You think that could be applicable to other parts of your acreage position outside of Martin?

Richard Dealy

Well, you're going to see different well results in all different areas. So the sale ranch happens to be one of our really good areas, so I don't think you would necessarily say that that's going to be the same exact result everywhere we drill but I think what you'll see is the same sort of upticks on lateral drilling or lateral extensions. And the way we look at it is where we are today, unless you stay out to 13,000 feet, is probably the economic limit in realizing if you're talking about extended reach drilling it could be tens of thousands of feet longer than that. The issue is these are wells in which we're pumping very large fracs so you have hydraulic limitations out at the toe where you're not going to be able to necessarily get off as an effective frac. And we think we're still pretty close to linear in terms of the relationship between lateral links out to 11,000 to 13,000 feet and productivity of the well.

In other words, one-to-one payout and we know the economics are strong from that standpoint. But I think we're almost at the limit in terms of the fact that even though we could drill longer wells, completing them becomes a hydraulic issue. And so I think that's probably about where we're going to stop but the more 13,000 footers you can do the better is our current view. So that means what we'll be trying to do is configure lease hold where we can to get out to 12,000 or 13,000 feet by doing acreage swaps and other trades.

Arun Jayaram

Great. My final question perhaps for Scott. Scott, you talked about when you get confidence around 50 you could increase your Permian activity by five to ten rigs. What about the Eagle Ford? At what oil price would you contemplate adding or restarting activity in the Eagle Ford?

Scott Sheffield

Yes. We have stated when oil gets to $50, which is an equivalent to the common same price that we would get, so if WDI gets to 50 we would look at restarting Eagle Ford. So we'll have to make a decision at the time if we had 10 rigs for instance and 17, do we take two of those rigs and put in Eagle Ford? For instance, we do have partners there, we have to get approvals on, but I could see us add a couple of rigs in Eagle Ford as a portion of that [indiscernible] rig add.

Arun Jayaram

Okay. That's very helpful. Thanks a lot.

Operator

Thank you. And we'll take our next question from Doug Leggate with Bank of America. Your line is open.

Doug Leggate

Thanks. Good morning, fellas. I'm looking at slide 12, Tim, and obviously very substantial improvement in the cost per foot, but kind of flattened out in the last quarter or so. I'm just wondering if you see – are we getting to the limits of the improvement now? Or do you think that's got further to go? And I've got a couple of follow-ups, please.

Scott Sheffield

I think if you're certainly looking an eyeball would say it's flattened out somewhat. It has to do, of course, with the mix of wells we're drilling and where they are and so on but we still have other areas where I think we can reduce our costs. We have – as I already mentioned, contracts that are peeling off from the standpoint of drilling contractors over this year into next year. And so coming off of what would've been mid-20s day rates into mid-teens is going to be a substantial effect for us. And there's other ancillary things that we're doing as well at the margin.

I think we can reduce our tubular somewhat from this point on as well, at least marginally, maybe 5%. But I think a lot of it will be not just the cost per se from existing contracts and existing supplies but rather continuing interest to improve and this has to do in our case with reducing nonproductive time as an example and we're splitting up both drilling and completions into small pieces to make sure we get can optimize. And so I think you'll start – you'll see us continuously improve but I think we are reaching more of a flat spot in the curve relative to where we were. You can see dramatic decreases in the early stages of what you would expect and now we're sort of reaching more of an asymptote but with a small decline going forward.

Doug Leggate

Okay. Thank you for that. Your comments, Tim, about the choking back for water management and so on, materially enough, you mentioned it in the slide deck. I'm just wondering if you could help us understand what that could mean for flattening out decline rates, for example in the areas where you're doing that. I mean, is that just kind of a one-off to deal with this water infrastructure issue? Or is it something that could become more of a policy for Pioneer going forward?

Timothy Dove

It's 100% today related to water, so we're not trying to effect EURs or wells by choking them back. We don't think there's actually any effect from choking wells back would amount to typically two to four weeks while this substantial water flow back period occurs. And So I think essentially what we're trying to do is optimize infrastructure. We could haul off this water but it's such a huge volume of water it creates a logistics problem and it's a minimum of 250 per barrel to do so.

And to go build bigger facilities, we all know the conundrum presented by that, which is we could actually build bigger facilities and they'd only be used for two weeks while we would basically see a decline in the initial production of the well both in terms of water and oil. And so this we think is optimal, it's simply just slightly choke back the wells until the facilities can handle the volumes considering the volumes are substantially higher. I think we'll see less of an effect on this as we get into the second quarter, as I mentioned, simply because we'll be drilling in different areas that won't have as close to existing infrastructure. Of course, that will require infrastructure buildout so there's no free lunches in this infrastructure business.

Doug Leggate

Thanks, Tim. Last one for me, if I may, and, Scott, I apologize for laboring the topic about what oil price you put rigs back to work, but it seems to be topic du jour. I just want to make sure I understood properly. So you're looking more at the strip than anything on the spot it sounds like and I'm just curious is that – you add a rig let's say tomorrow, when would you expect production contribution given your pod drilling? And I'll leave it there. Thanks.

Scott Sheffield

Yeah, I think we're down to spud to pop of 120 to 130 days, so we used to say six months, so it's down in the four or five month range. So when we add rigs it'll take four to five months and it's a bigger picture for the industry. I think the industry is going to – we just can't become a big shale swing producer like OPEC thinks just because of the combination of leverage, the amount of people we had to get back to work. It's going to take the industry a good year-and-a-half, two years to get production going again once it starts back up.

Doug Leggate

[Indiscernible] Thanks, Scott. I appreciate the time.

Operator

Thank you. And we'll go now to Neal Dingmann with SunTrust. Your line is open.

Neal Dingmann

Good morning, guys. Say, I just got a question, I know there's a couple packages, one – or at least one or two large floating around the Midland. Your thoughts about looking at some of these maybe at least to fill in acreage. I know you certainly don't have a cost-to-inventory issue, so I'm thinking more, Scott, about just filling in acreage. Are these things that you all are looking at?

Richard Dealy

Yes. Our standard is still to look at anything that's contiguous next to our acreage that will extend our laterals. So far, we're only spending $10 million, $20 million a year but if we see something that will definitely improve our laterals from 5000 to 10,000 to 12,000 feet, we'll definitely look at it. The prices people are paying are still fairly strong. So we'll just have to evaluate and see as these deals come through our system.

Neal Dingmann

Okay. Okay. And, Scott, for you – maybe for you or maybe for Tim. I'm just looking at slide eight. I want to make sure where it does show kind of how you – you [indiscernible] type curves in the northern Spraberry and Wolfcamp. And especially I'm just looking at that Wolfcamp B, talking about that 35% improvement. Is that pre-sort of all the additional profit along the laterals and all these other things you've already done? I'm just trying to get a sense of that certainly shows strong in all three of those curves, particularly in the Wolfcamp B. I'm wondering is that before some of these other things you've just now started doing?

Scott Sheffield

Yeah, so I would simply say if you look at the completion optimization campaign slide, if you consider what we used to do in 2013 and 2014 is 1.0, it's really the 2.0 case where all those wells were completed using various completion optimization techniques but they did not include any what we call 3.0, which is 2016 campaign.

Neal Dingmann

Wow. Okay. So there's really room to – I guess the last question I had then, how much until you have the confidence, I mean again, certainly a million barrels is already great EUR. How much more would you have to see or how much more just timing in our data would you have to see to decide to even take those type curves a bit higher?

Frank Hopkins

Hey, Neal. This is Frank. Again, I'll just sort of repeat what I said earlier. I think when you get well into the second half of this year – I don't know whether it's third quarter or fourth quarter but in some cases the results we have are only, you know, we've only got 90 days of results but everything is looking positive. So give us a couple more quarters, certainly on the Wolfcamp B, and I think we'll be able to declare an increased level, a new EUR, whatever you want to call it there and up the EURs we're building into our forecast. And then with respect to A and the Lower Spraberry shale, we'll be getting a lot more data over the second half of this year, but our data set is not nearly as extensive as we have with the Wolfcamp B. So we're probably looking sometime into 2017 until we get enough confidence there that we want just – I call it declare a victory.

Neal Dingmann

Certainly. Certainly. Makes sense, Frank. Thanks a lot. Go ahead.

Operator

Thank you. We'll move next to Charles Meade from Johnson Rice. Your line is open.

Charles Meade

Good morning, Scott and Tim and to the rest of the team there. I wonder if I could ask a question about the completion optimizations and how far things might go. One way of looking at it is that you could spend a million bucks to bring on – or for an increment as small as 100,000 barrels and that would still benefit your F&D. And I'm curious, how close is that to the way you guys are analyzing it? And what might be left out of the picture when we look at it that way?

Richard Dealy

I think that's exactly the right math when you consider, Charles that our F&D costs for this part of our business horizontal Wolfcamp Spraberry drilling is roughly about 10. So $10 is a good F&D cost but I think what we're really finding is that increments we're talking about are substantially more than 10% as we're showing in some cases where they're 25%, 35. The real question is as we get to a point here in the 3.0 model that I was referring to, we're already down to 15-foot cluster spacing.

I don't really know how much closer you can get clusters but it's not much closer than that. And I think you're at a point where even pumping profit, even though we're 1700 to 2000 pounds of profit, we see some plays where they've got the 2500, 3000 so we maybe have a little marginal ability to move more that direction but I think the more of the same model is something we're really testing in 2016. You're going to see improvement, I think, out of a lot of those techniques. The issue is going to be once you get past there and you can't really do more of the same because you're limited by space or volume or physics, what do you do there? Then you're probably more into new technology applications, which are little bit unclear today.

Charles Meade

Right. Yeah, I remember you mentioned that earlier in your prepared comments, Tim. And if we could stick on that, your new iteration of the completion design, you talked about the 80 wells in the back half or the remainder of this year. Is there going to be any shift in the mix of those wells versus what we've seen to date? Or should we still expect two-thirds, three-quarters Wolfcamp B will this newest completion design?

Richard Dealy

I don't anticipate the mix of optimally completed wells will change compared to just the totality of the program.

Charles Meade

Great. Thank you for that.

Richard Dealy

See you, Charles.

Operator

Thank you. We'll move next to Scott Hanold with RBC Capital. Your line is open.

Scott Hanold

Thanks. Good quarter, guys. If I could refer to Page 10, Tim, just to clarify, so on version 3.0 specifically from our seats what should we be looking at in terms of relative productivity to make this an economically feasible plan to move forward? Certainly you're seeing a nice 10% to 35% increase or I guess even on just the Wolfcamp B 35% increase on version 2. Is that the type of increment that you'll need to make that decision on a go-forward basis or what should we look for?

Timothy Dove

I kind of refer back to Charles' question in the sense that version 3.0 has us adding somewhere between $500,000 and $1 million per well. You use a $10 F&D cost, you better feel pretty good that you're getting that kind of percentage increment as well, which is on a well cost basis probably 10%. So you better feel like you're getting at least a 10% bump or you probably wouldn't proceed, but so far our bumps have been substantially higher. Remember back to the Eagle Ford shale, we stopped when we were at a point when we were generating 15% to 30% increments but we're not stopping here.

And the other thing that occurs to me in that question is we're not even talking about spacing. What happened in this field was we began by looking at 500 to 600 foot spacing and we had situations where we had what we thought was too much well interference at a time we were drilling larger half-length wells – I mean completions. That was really kind of a 1.0 model. Since then, we now find we're completing the wells with more near well bore rock stimulation. That allows for the potential for tightening spacing. So we're now actually testing down to again down to 500 or 600 foot spacing where we had blown it out to 900 to 1000 for that concern regarding interference. So now you're talking about substantial incremental improvements in overall EURs from selected field areas. In other words, your recovery rates go up. So we're not even referring to that, but behind the scenes that's also going on we just don't have any data yet to show you but it's just another thing on the list to hopefully essentially increase EURs.

Scott Hanold

So just to clarify there, 2.0 assumes somewhere 500 or 600. I know it's early, but is that what you're refer to?

Timothy Dove

2.0 – 1.0 is I'd say we tried down to 500 to 600. We saw interference in some wells back in 2013/2014 to the point we were concerned about it and thought we might be over stimulating the rock and therefore moved out to 800 to 900 foot spacing, some cases 1000 feet. And some of the more recent testing we're doing now, we're moving back to 500 to 600 because we think that the more near well bore rock stimulation campaign is presented by the 3.0 case will allow us to do that. So when we're talking about the moving back to 500 to 600 is actually a 3.0 scenario.

Scott Hanold

Okay. Understood. So of those 80 wells that you're drilling, they will likely be 500 to 600, if I'm hearing you correctly. And could I also ask you can you give us a sense – are you looking at doing A/B lower Spraberry all at once or how are you orientating these wells?

Timothy Dove

Well, we still continue to use, on the last part of your question, the drilling a bunch of Wolfcamp BS. You can see the predominance of the wells being drilled and then with the waiting period following up on Wolfcamp A and then it's just going to continue to be the plan. And so I would see that going forward as well.

Scott Hanold

Okay. Thank you.

Operator

Thank you. We'll take our next question from Evan Calio from Morgan Stanley. Your line is open.

Evan Calio

Good morning, guys. A couple of follow-up questions on your rig deployment comments. Fifty is the threshold that relates to your ability to hedge, 50 on the downside. What percentage of 17 do you need to hedge at those levels in order to add rings? Is there trigger level there?

Timothy Dove

We have historically, Evan, gone up to 75% to 85% so it will be somewhere in that range. We're not...

Evan Calio

And now...

Timothy Dove

We're not going to give that what hedge position we're going to put in because there's too many people hedging in the market in this day and time but obviously it'll be hedges trying to collect as close to 50 as we can.

Evan Calio

Right. And that hedge would then allow you to add the first rigs, I guess as the first five cold stacked rigs. Is the next five rigs then up for the ten based upon oil price scenarios S&D outlook?

Timothy Dove

No. The entire five to ten is based on the strip getting to $50 for 17 and also believing that the fundamentals are strong such as inventories are declining. We would not like to add – it's not ideal to add the rigs at once. We'd like to add two or three one month, two or three the next month, two or three the next month. And so we'll probably have a phase-in time period.

Evan Calio

Great.

Timothy Dove

And we could – we'd like to also maybe do it later this year, so if we can achieve those fundamental goals and also the oil price goal.

Evan Calio

Great. Any range on vertical integration CapEx increase under a five to ten rig addition program from the 150 this year?

Timothy Dove

I don't think...

Scott Sheffield

Our fleets can handle it right now.

Timothy Dove

Can handle it so I don't think there will be an increase.

Evan Calio

Great. Maybe last for me, if I could. Could you guys discuss any technical challenges that remain to wider deployment of longer lateral versus your 9500 foot standard design? And what percentage – I appreciate the levels for 2016 but what percentage of those lateral length – of those longer laterals could be in your 2017 program? Thanks.

Scott Sheffield

The only technical hurdle is the one I mentioned which has to do with the fact that the longer laterals present more of a completion issue than they do anything else. Realize you get far out in the well bore you have hydraulic issues that may be a limiting factor in terms of how well the completions are pumped at the toe. Also, remember we are using still a plug and perf model here for how these wells are completed and so your drill-out campaign becomes much more difficult especially if you're using coil or what have you at that length.

So it really becomes more mechanical on the completions than it does the drilling. I don't really see us out testing much more in terms of lateral length than out there to the 12,000 to 13,000. But as I mentioned, we have probably over 60% of our acreage today is amenable to +10,000 foot drilling. We're going to have 15, probably 10, 15, 20 wells that are out past 10,000. We've got some work to do to really configure more of our lease hold to add that other 40% for long laterals as well.

Evan Calio

Great. So some higher number in 2017, but we'll stay tuned for that.

Scott Sheffield

Yeah, we're heading that way. That seems to be the right economic decision to get as long lateral out there as we can and so I would see us pushing in that direction.

Evan Calio

All right. Appreciate it, guys.

Operator

Thank you. We'll take our next question from Ryan Todd with Deutsche Bank. Your line is open.

Ryan Todd

Great. Thanks. Good morning, guys. Maybe just one follow-up question on the other side of the rig acceleration. I know you've talked a lot about when you would add rigs, but if we think about on the higher side. What are some of the limits in terms of how much capital you'd want to deploy? I think in the past you've talked about a one-and-a-half time's leverage as kind of a high end of a target. If you think about how much capital you could eventually push into the market, is balance sheet metrics still kind of a limiting factor? Is it – are there infrastructure limitations or bottlenecks that we should be aware of? Or how are you thinking about your additional to deploy, whether it's five or ten or fifteen or more?

Richard Dealy

Yeah, five to ten first is cash flow. We're going to have a strong cash position by the end of 2016 obviously and then going into 2017, I do expect oil prices to continue to move on up past $50 toward $60 going into 2018. So we'll continue to add rigs. Our cash flow starts getting to a number close to 2 billion plus. You start talking about those types of numbers so we will start paying for ourselves, our rig costs and we'll use the balance sheet. I think it's probably even more important and I think other companies will probably lower their targets. Too many companies were at two, two-and-a-half to one and they got caught with the downturn and they're up to four to five to six to one. And so it's probably even more important for the company to keep the debt-to-cash flow at five to one as a limiting factor going forward.

Ryan Todd

Great. I appreciate that. And then maybe [indiscernible] it feels like a ways away at this point but you've talked in the past about eventually wanting to target cash flow neutrality in the medium term. Is that still a medium term outlook? Is that a long ways away for us to worry about at this point? Or how do you think towards long-term managing to that target?

Richard Dealy

Managing – say again.

Ryan Todd

Managing to a cash flow neutral position.

Richard Dealy

Yeah, I think if oil prices get back up to 60 and we don't see a – we see a very small increase in service costs, it depends on how many rigs are being added, that the company can grow within its cash flow at that point time. Once we spend our cash flow and get production up and assuming some small increases in service costs, I think the company can live with any cash flow at that point in time.

Ryan Todd

Great. Congrats, guys. I'll leave it there.

Operator

Thank you. We'll take our next question from Brian Singer with Goldman Sachs. Your line is open.

Brian Singer

Thank you. Good morning. To follow up on a couple of the topics from earlier, first on the longer laterals. What percent of your northern acreage could you today apply 10,000 foot laterals? And can you give us some sense of your expectations for the magnitude of acreage slots you think we could see this year and how much have a greater percentage of your acreage that could open up to longer laterals?

Timothy Dove

Well, I think I've already mentioned, Brian, that about 60% of our current acreage would be amenable to 10,000 foot laterals or more today. We're doing acreage swaps essentially every day or close to it. We have internal goals in that regard. I remind you that one of the more recent deals we did had us swapping out 1200 acres and this is acreage for acreage with no cash changing hands and we added 210,000 feet of laterals. So it's basically – I think it will be easily something we would look at as a goal to add 2 million feet of laterals as a goal for 2016 and this is just stacking onto our existing acreage position.

Brian Singer

Got it. And the 60% is Northern or total at Permian acreage?

Timothy Dove

I'm speaking more Northern right now because that's the only place we're doing any drilling.

Brian Singer

Got it. Okay. And then if and when it does make sense to start adding five to ten rigs, would the completions associated with the new rigs all be the version 3.0 and would you characterize the wells drilled as more development mode in areas that are all fully tested for the zones you – for the lower Spraberry A and B? Or would they be more delineation drilling testing new zones in portions of your acreage, testing spacing, et cetera?

Timothy Dove

Well, I'm first going to just say this – we only have an 80-well campaign going right now on 3.0. So we're not going to make further decisions the expansion of the use of 3.0 until we understand whether it's working and if so at what sort of economic basis that it's working. So to the extent we were to add new rigs, we'd have to kind of hold off and see how 3.0 works. If we think 3.0 works well, then we would absolutely add it to every single well. It would be part of the five to ten rig adds. In terms of the zones, the way I think about this, when I consult with our geo team, we should know with the plethora of data we have vis-a-vis the Wolfcamp B and the 3.0 campaign going on in the B this year, we should pretty much be at a point we will be in full development mode on B at an optimal completion by the end of this year.

But in the case of the Wolfcamp A and then further to the Lower Spraberry shale, we just don't have as much data. So it might be into 2018 before you can really say we are in development mode at the optimal way these wells are to be completed. So I think it's going to be a staggered approach. You can't get all the data every – today on every single zone at the speed in which we're drilling, but we're trying to accumulate it as fast as we can but I would think Wolfcamp B ready by the end of the year to be on full development mode A and Lower Spraberry shale into 2018 and 2019.

Brian Singer

Great. Thank you.

Operator

Thank you. This does conclude our Q&A session for today. I'd like to turn the call back to Scott Sheffield for any closing remarks.

Scott Sheffield

Again, we thank everyone for taking their time out. Again, reminding people that we had a great quarter. Looking forward to the next quarter and continuing with our outstanding performance. Thank you.

Operator

And this does conclude today's conference. Thank you for your participation. You may disconnect at any time.

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