先鋒自然資源 (PXD) 2016 Q1 法說會逐字稿

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 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 and webcasts.

This call is being recorded. A replay of the call will be archived on the internet site through May 20th.

The Company's comments today will include forward-looking statements made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in 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.

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 will 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. Rich will then cover the first-quarter financials and provide guidance for the second quarter of 2016. And after that, we will open up the call as always for your questions.

So Scott, I will turn the call over to you.

Thank you, Frank. Good morning. Slide number 3, 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 a day equivalent to 2016, an increase of 7,000 barrels a 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 of our gross production in the Spraberry/Wolfcamp fields exceeded 200,000 barrels a day equivalent for the first time, and total field production has exceeded or surpassed 1 million barrels of oil equivalent per day and still growing. Probably the only field growing in today's environment in North America.

We placed 55 horizontal wells in 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 enhancing well productivity. Drilling and completion efficiencies and cost reduction initiatives are still driving down costs per lateral foot.

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

We also added the recently Targa-operated Spraberry/Wolfcamp gas processing plant of 200 million a day. It's online. It essentially is up to about 120 million a day, but that came from other plants which reduced their intake in those other plants. So there's plenty of room for the next two or three years for additional capacity.

Pioneer, just to remind people, we do own 27% of this system. Increased oil and gas derivative coverage for 2017, we've already released these numbers and we'll talk a little bit more about it, moving all the hedges up primarily 50% for 2017.

Slide number 4 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're currently operating 12 horizontal rigs in the north and two in the south. The two in the south will be terminated by the end of June. As I have mentioned on previous calls, our partner Sinochem will look more at a $50 oil price to re-initiate 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 continue to progress its completion optimization program. The higher forecasted growth rate reflects the improving Spraberry/Wolfcamp well productivity.

We're keeping our planned capital expenditures the same for both drilling activity and vertical integration spending at $2 billion for 2016, $1.85 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, that Pioneer expects to add 5 to 10 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? What's ideal? The strip in 2017 has moved up to about $47, $47.50 for oil. Today's price is close to $44.

So if we see the strip in 2017 for instance get up to $50, and we see inventories starting to decrease, which gives us confidence in the supply/demand fundamentals, we know the supply side is dropping. The US should see a significant drop in the third quarter on US shale. Probably a good 400,000 or 500,000 barrels a day just in that quarter, the third quarter especially as reported by the EIA.

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. 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 to 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 a 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 will fund our July 2016 and March 2017 senior note maturities. An additional $0.5 billion will come in July of 2016 from our Eagle Ford sell -- midstream sell business that we did in 2015.

Pro forma net debt to 2016 operating cash flow of 0.4 times. At the end of the first quarter, we had a debt to book of 10%.

Going to slide number 6, no change in our capital program. I think the only change on this slide is the fact 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 will be up closer to $1.5 billion so that gives us an extra $100 million to $200 million of cash that will be added into our coffers by the end of 2016.

Slide number 7. 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% oil 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 2016-2018 period. Obviously, it will depend on the pace of the commodity price recovered.

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

Thanks, Scott. I will turn now to slide 8 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 would point you to the graph on the top left. This is the Wolfcamp B graph, which shows all of the wells that have been completed utilizing our optimization campaign since 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 those wells in terms of the early production, and you can see it's pretty clear that blue line far exceeds the 1 million barrel BOE type curve shown below. In fact, we would calculate that the early production rates 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, only 13 wells since 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 1 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 1 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. 42 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 will talk more about that in a couple slides ahead.

On slide 9, 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 Wolfcamp B again. In this case, about a 25% improvement over that 1 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 on 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 and 2014, which was early days in terms of the play, and it generally had us with probably no more than 1,000 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 wellbore. 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 1,400 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 the 9,000-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 2,000 pounds per foot. 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 that additional amount of fluid and profit and so on does add about $0.5 million to $1 million per well. And I think it's -- we believe that the optimization actually will actually have a positive payout, but stay tuned on that because we really 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're trying to do is now design completions to allow more rock near the wellbore 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 in planning to plan 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 mention 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 are out at roughly about $10 million each. Early data looks very encouraging.

As shown here on the graph on the bottom, you see on 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 gray curve. It's pretty clear to see that the longer laterals are in fact contributing really substantial improvements over their earlier predecessors, which were more like 9,500-foot laterals and 7,000-foot laterals.

So I think it's pretty clear we continue to see a very strong correlation between lateral length, perforated lateral lengths, and well productivity. We continue to see that as we look forward. I would say that we do the calculations, over 60% or so of our acreage is amenable to, based on the leasehold 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 the year-end 2014 until the first quarter in terms of our drilling and completion cost 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 a very high day rates in the mid-$20s where today's rates are probably more in the mid-teens. So we'll 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 increase substantially from about 800 feet per day of lateral section completed to about 1,200 feet per day during the first quarter.

That translates directly into speed of the job as well as in addition, the cost reductions to 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. 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. Scott mentioned the fact we'll be drilling with the 12 rigs in the north with about 230 wells to be put on production. Our mix of wells still is predominantly Wolfcamp B and Wolfcamp A. The mix essentially remains the same.

What was now the -- what was 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 9,000-foot laterals. In addition to which to the extent the optimization is completed on those wells in the new style of optimization, we add another $0.5 million or $1 million per well.

One advantage we have in this field is a tremendous opportunity presented by low LOE. It's because these are very high-volume wells, and they typically run $3 to $5 per BOE in terms of lease operating expense.

When you add taxes on, you have a very favorable $5 to $7 total cost to operate these wells. That's one of the reasons, Rich will comment on this, but you continue to see our LOE per BOE reduced through time simply because as we add more of these horizontal wells into the mix, it just drives down our averages in terms of LOE.

Economics still look good. I think they're still conducive to our drilling activity. Certainly with regard to where the 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 to 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 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 162,000. 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 to about 9% since the fourth quarter 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 the 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're 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 and 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 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 will 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 would 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 the standpoint of our full-year results.

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

Thanks, Tim. I'm going to start on slide 15 where we reported a net loss attributable to common stockholders at $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, it included unusual items aggregating at $52 million loss or $0.32 per diluted share principally related to two impairments, one in the West Panhandle field and one in Alaska where we held a royalty interest in 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 expiration so that was just a cost savings decision to do that. So after adjusting for the unusual items that Scott mentioned, we're at $104 million loss or $0.64 principally attributed to the lower commodity price environment that we're dealing with.

If you look at the bottom of slide 15 where we show Q1 guidance versus results, Scott talked about the outperformance on production. Then if you look at really the rest of the items, they were either on the positive side of guidance or within guidance throughout this. 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 where we brought in 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 would point out at the bottom on our NYMEX differential for oil for the first quarter, you can see it was up a little over $1 the differential, that's predominantly due to Eagle Ford condensate sales. Last year, if you recall we were exporting about 20,000 gross barrels a 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 costs which will help to 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 of $1.1 billion, that's net of cash on hand, and our liquid investments about $2.5 billion. We still expect to get the $500 million in July from our Eagle Ford midstream business sale that we did last year that will come in July. Undrawn credit facility of $1.5 billion still completely unused.

As you are aware, we have prefunded 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. 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 would 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 BOEs 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 will let you read through those but consistent with what you would have saw for first-quarter actual results.

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

(Operator Instructions)

We'll take our first question from John Freeman with Raymond James. Your line is open.

Good morning, guys. Terrific quarter.

Thanks, John.

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

Yes, John, I would say first of all, we did -- because of the efficiency complete a few more wells, really a handful, probably 10 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 -- and 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 these can be more of an all of the above. I think you are going to see continuous gains and I think you'll see us hopefully continue to outperform.

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 are going do on these 80 wells? Like that was just straight lateral length longer versus the others.

Yes, 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 would compare them exactly with all the rest of the wells that were drilled prior.

Perfect. Great quarter, guys. Thanks.

Thanks, John.

We'll move next to Dave Kistler with Simmons & Company.

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.

Okay, Dave. Yes, 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 weather.

I already mentioned the fact that we had, let's say 10 additional completions. Really semi-immaterial for the first quarter because they were late in the quarter. It has all to do with well productivity.

This has to do with the fact that the graphs I have 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.

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

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

And then following up also, last quarter you had guided to shut-ins as a result of fracking offsetting wells. When you guys kind of think about that going forward, will there be kind of 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?

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. I would anticipate that number to come down somewhat.

Appreciate that. Then one last one.

When you talk about adding incremental rigs, kind of 5 to 10 and staging them in, can you talk a little bit about how you sit with respect to personnel to handle that ramp-up? Maybe specifically with the tool pusher or the effective driller on each one of those rigs?

Actually, we had the good fortune of hanging around with some of our drilling contractors the last few days, and they are ready to add rigs. They're getting pinged upon right now by industry as you might expect to start potentially adding rigs.

They would make the case that if you were talking about a handful of rigs like we are, and let's just say 5 to 10 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.

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. So we won't miss a beat. I think our drilling contractors will be there with us in good shape at least for this first tranche.

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

Thank you. We will move next to Arun Jayaram from JPMorgan.

Good morning, gentlemen. I wanted to 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 have 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 in the new guidance?

Basically, what we've done is we've 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, 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 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 where we will 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 enough data. 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.

That's helpful, that's helpful. Just a second question, perhaps Tim. In terms of lateral lengths, you have been drilling wells in that 8,200 to 9200 foot range.

You've obviously announced some results on wells beyond 10,000 foot. Are you -- have you had any conclusion on what you think the optimal lateral foot could be in terms of drilling, and some of the wells in the Sale Ranch? You think that could be applicable to other parts of your acreage position outside of Martin?

You're going to see different well results in all different areas. 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 will see is the same sort of upticks on lateral drilling or lateral extensions.

The way we look at it is where we are today -- unless you say out to 13,000 feet is probably the economic limit and realizing if you're talking about extended reach drilling, it can 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.

We think we're still pretty close to linear in terms of the relationship between lateral lengths out to 11,000 to 13,000 feet and productivity of the well. In other words, 1-to-1 payout. 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 can drill longer wells, completing them becomes a hydraulic issue. 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 kind of our current view. So that means what we'll be trying to do is configure lease oil where we can to get out to 12,000 to 13,000 feet by doing acreage swaps and other trades.

My final question, perhaps for Scott. Scott, you talked about when you get confidence around $50, you could increase your permitting activity by 5 to 10 rigs.

What about the Eagle Ford? At what oil price would you contemplate adding or restarting activity in the Eagle Ford?

Yes, we have stated when oil gets to $50, which is an equivalent to the condensate price that we would get. So if WTI gets to $50, we would look at restarting Eagle Ford. So we'll have to make a decision at the time. If we add 10 rigs, for instance in 2017, do we take 2 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 rigs in Eagle Ford as a portion of that 10 rig add.

That's very helpful. Thanks a lot.

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

Thanks. Good morning, fellows. I'm looking at slide 12, Tim. 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.

I think it, yes, certainly looking at the eyeball test would say it's flattened out somewhat. It has to do of course with the mix of wells we're doing, 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 have been mid-[20s] day rates into mid-teens is going to be a substantial effect for us. There's other ancillary things that we're doing as well at the margin. I think we can reduce our tubulars 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 just to improve and this has to do in our case with reducing non-productive time, as an example. And we're splitting up both drilling and completions into small pieces to make sure we can optimize. You will see us continually 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 expect, and now we're sort of reaching more of an asymptote but with a small decline going forward.

Thank you for that. Your comments, Tim, about the choking back for water management and so on, materially enough that 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. Is that just 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?

It is 100% today related to water. So we're not trying to affect EURs or wells by choking them back. We don't think there's actually any effect from choking the wells back but would amount to typically two to four weeks while this substantial water flowback period occurs.

So I think essentially what we're trying to do is optimize infrastructure. We could haul off this water, but there's such a huge volume of water it creates a logistics problem and it's a minimum of $2.50 per barrel to do so. To go build bigger facilities, we all know the conundrum presented by that which is we could actually build bigger facilities and they would 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.

This we think is optimal. It's just 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 will be drilling in different areas that won't have us as close to existing infrastructure.

Of course, that will require infrastructure buildout. So there's no free lunches in this infrastructure business.

Thanks, Tim. Last one from me, if I may, and Scott, I apologize for laboring the topic about what oil price you put rig spot to work but it seems to be topic de jour. I just want to be sure I understood properly. You're looking more at the strip than anything on the spot, it sounds like.

I'm just curious, is that -- if you had a [rig light] say tomorrow, when would you expect production contribution given your pad drilling? And I'll leave it there. Thanks.

I think we're down to spud to POP of 120 to 130 days. We used to say six months. It's down in the four or five month range.

So when we add rigs, it will take four to five months. 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 have to get back to work. It's going to take the industry a good 1.5 years, 2 years to get production growing again once it starts back up.

So it's kind of getting up. Thanks, Scott. Appreciate the time.

And we'll go now to Neal Dingmann from SunTrust. Your line is open.

I've just got a question, I know there's a couple packages, one couple -- or at least one or two large floating around in Midland. You had thoughts about looking at some of these, maybe at least to fill in acreage.

You certainly don't have any close to inventory issue. I'm thinking more, Scott, about just filling in acreage, things that you all are looking at.

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 5,000 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.

Okay. Scott, for you, or maybe for Tim. Just looking at that slide 8, I want to make sure where it does show how you're beating all those type curves in the northern Spraberry and Wolfcamp.

Especially I'm just looking at that Wolfcamp B, talking about that 35% improvement. Is that pre all the additional proppant, the longer 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 on the Wolfcamp B. I'm just wondering is that before some of these other things you have just now started doing?

I would simply say if you look at the completion optimization campaign slide, if you consider that 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.

Wow, okay. So there's really room to -- I guess the last question I had then, how much until you have the confidence? Again, certainly a million barrels is already a great EUR.

How much more would you have to see or how much more just timing or data would you have to see to decide to even take those type curves a bit higher?

Hey, Neal. This is Frank. Again, I will 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 -- 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 the A and 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 to just -- I will call it declare a victory.

Certainly, certainly. Makes sense, Frank. Thanks a lot.

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

Good morning, Scott and Tim, and to the rest of the team there. I wonder if I could ask a question about these completion optimizations and how far things might go.

One way of looking at it is that could you spend $1 million to bring on or for an increment as small as 100,000 barrels, and that would still benefit your F&D. 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 it way?

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 the increments we're talking about are substantially more than 10% as we're showing 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.

I think you're at a point where even in pumping proppant, even though we're 1,700 to 2,000 pounds of proppant, you see some places where they've got to 2,500, 3,000 pounds, so we maybe have a little marginal ability to move more that direction. But I think it's more of the same model is something that we're really testing in 2016. You are 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 are limited by space or volume or physics, what do you do there? Then you're probably more into new technology applications, which are a little bit unclear today.

Right. 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 80 wells in the back half or in 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 with this newest completion design?

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

Great. Thank you for that.

Okay, Charles.

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

Thanks. Good quarter, guys. If I could refer to page 10, Tim.

And 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 just on the Wolfcamp B, 35% increase on version 2.0. Is that the type of increment that you will need to make that decision on a go forward basis or what should we look for?

I kind of refer back to Charles' question in the sense that version 3.0 has us adding somewhere between $0.5 million and $1 million per well. If 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 in the neighborhood of 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.

If you remember back to Eagle Ford Shale, we stopped when we were at a point where 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. We had situations where we had what we thought was too much well interference at a time when we were drilling larger half-length wells, I mean completions. That was really kind of the 1.0 model.

And since then, we now find we're completing the wells with more near wellbore rock stimulation. That allows for the potential for tightening spacing, so we're now actually testing down to again, down to 500- to 600-foot spacing where we had blown it out to 900 to 1,000 for that concern regarding interference.

So now you're talking about substantial incremental improvements in overall EURs from selected field areas. So 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.

Just to clarify there, 2.0 assumes somewhere 500 to 600. I know it's early, but is that what you're referring to?

1.0 is I would say, we tried down to 500 to 600. We saw interference in some wells back in 2013-2014 to the point where we were concerned about it and thought we might be overstimulating the rock and therefore moved out to 800- to 900-foot spacing, in some cases 1,000 feet.

In 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 wellbore rock stimulation campaign as presented by the 3.0 case will allow us to do that. So what we're talking about then moving back to 500 to 600 foot is actually a 3.0 scenario.

Okay. Understood. Of those 80 wells that you're drilling, those will likely be 500 to 600 if I'm hearing you correctly.

Could I also ask you, can you give us a sense, are you looking at doing A/Bs, Lower Spraberrys all at once, or how are you orientating these wells?

We still continue to use, on the last part of your question, the drilling a bunch of Wolfcamp Bs. As you can see, they are still the predominance of the wells being drilled.

And then with the waiting period, following it up with Wolfcamp As. I think that's going to continue to be the plan. I would see that going forward as well.

Okay, thank you.

Thank you. We'll take our next question from Evan Calio from Morgan Stanley.

A couple follow-up questions on your rig deployment comments. If $50 is the threshold that relates to your ability to hedge $50 on the downside, what percentage of 2017 do you need to hedge at those levels in order to add rigs? Is there a trigger level there?

We have historically, Evan, have gone up to 75% to 85%. So it will be somewhere in that range.

We're not going to give out 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 will be hedges trying to collect as close to $50 as we can.

Right. And that hedge would then allow you to add the first rigs, I guess the first five cold stacked rigs. Is the next 5 rigs then up for the 10 based upon oil price and your S&D outlook?

No, the entire 5 to 10 is based on the strip getting to $50 for 2017, 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 10 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. So we'll probably have a phase-in time period.

We would like to also maybe do it later this year. So if we can achieve those fundamental goals and also the oil price goal.

Great. Any range on vertical integration CapEx increase under a 5 to 10 rig addition program from the [$150 million] this year?

I don't think --.

Our fleets can handle it right now.

I don't think there will be an increase.

Great. Maybe last for me, if I could. Could you guys discuss any technical challenges that remain to a wider deployment of longer lateral versus your 9,500-foot standard design?

And what percentage? I appreciate the levels for 2016, but what percentage of those lateral lengths -- of those longer laterals could be in your 2017 program? Thanks.

I think 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. Realizing you get far out in the wellbore, 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're using still a plug and perf model here for how these wells are completed.

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 feet.

As I mentioned, we have probably over 60% of our acreage today is amenable to plus 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 some more of our leasehold to add that other 40% for long laterals as well.

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

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

All right, appreciate it, guys.

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

Great, thanks. Good morning, guys. Maybe just one follow-up question maybe 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 of what are some limits in terms of how much capital you would want to deploy. I think in the past you've talked about a 1.5 times 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? Are there infrastructure limitations or bottlenecks that we should be aware of? How are you thinking about your additional to deploy, whether it's 5 or 10 or 15 or more?

5 to 10, 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, towards $60, going into 2018. And 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 type of numbers and 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 2-, 2.5-to-1, and they got caught with this downturn, and they're up to 4- to 5- to 6-to-1. So it's probably even more important for the Company to keep this debt to cash flow of 1.5-to-1 as a limiting factor going forward.

Great. I appreciate that. And then maybe, over the medium term, 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 the medium-term outlook? Is that a long ways away for us to worry about at this point or how do you think towards longer term towards managing that target?

Managing -- say it again.

Managing to a cash flow neutral position.

Yes, I think if oil prices get back up to $60, we don't see -- 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 in time. Once we spend our cash flow, 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.

Great. Congrats, guys. I will leave it there.

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

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 swaps you think we could see this year? And then how much of a greater percentage of your acreage that could open up to longer laterals?

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 will remind you that one of the more recent deals we did had us swapping out 1,200 acres, and this is acreage for acreage trade with no cash changing hands. We added 210,000 feet of laterals.

So it's basically -- I think it would be easily something we would look at as a goal to add 2 million feet of laterals as a goal for 2016. This is just stacking on to our existing acreage position.

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

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

Got it. Okay. And then if and when it does make sense to start adding 5 to 10 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?

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 on 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, I'd have to kind of hold off and see how 3.0 works. If we think 3.0 works well, then we'd absolutely add it to every single well. It would be a part of the 5 to 10 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 where 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 going to be completed.

I think it's going to be a staggered approach. You can't get all the data today on every single zone at the speed at which we're drilling, but we're trying to accumulate it as fast as we can. I would think it's Wolfcamp B ready by the end of the year to be on full development mode, A and Lower Spraberry Shale into 2018 and 2019.

Great. Thank you.

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

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.

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