先鋒自然資源 (PXD) 2016 Q2 法說會逐字稿

Welcome to the Pioneer Natural Resources second-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 and Investor Relations.

Pioneer has prepared PowerPoint slides to supplement their comments today. Their slides can be accessed over the Internet at www.PDX -- I'm sorry, PXD.com. Again, the Internet site to access the slides related to today's call is PXD.com. At the website, select Investors then select Earnings and Webcasts.

This call is being recorded. A replay of the call will be archived on the Internet site through August 22, 2016.

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 and Investor Relations, Frank Hopkins. Please go ahead sir.

Thank you Rachel. 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 second quarter of 2016, another great quarter for Pioneer, saw the Company continue to deliver solid execution and outstanding performance. Scott will then review our latest outlook for Pioneer through the end of this decade. After Scott concludes his remarks, Tim will discuss our 2016 capital program and provide more color on our production forecast through 2020. He will also provide an overview of our recently announced Midland Basin acreage acquisition from Devon and review our continuing strong horizontal well results and capital efficiency improvements in the Spraberry/Wolfcamp. Rich will then cover the second-quarter financials and provide the earnings guidance for the third quarter. After that, we will open up the call, as we always do, for your questions. So with that, I'll turn the call over to Scott.

Thank you Frank. Good morning. This is the first call since my announcement to retire as CEO. I want to give a few comments before I go over the first two slides.

I may be setting a record, but I'm getting close to 100 earnings calls since 1991, so 25 years of earnings. Times four, it's about 100 years with one left. I think every leader wants to retire and pick the best time. I thought that 2014 was that time, but seeing what the Company has done through this downturn over the last two years, 2016 is obviously the best time.

The Company has the best rocks, deepest inventory with the lowest cost basis in the industry, the best balance sheet. What's more important with Tim and the management team is they've been with me over 20 years. We've got the best management team in the business, and I'll make a few comments on our -- the best long-term growth profile of any large-cap company out there.

I've only got a couple of slides as I transition to Tim, so we can start off with Slide number 3. For the quarter, the Company had an adjusted loss of $37 million or $0.22 per diluted share, production way above guidance. The second quarter was 233,000 barrels of oil equivalent per day, 58% oil. That's up from 55% oil in the first quarter. Again, above the guidance, an increase of 11,000 barrels a day or 5% versus first quarter. Oil production up 12,000 barrels a day or 10% versus first quarter 2016. Growth driven by the Spraberry/Wolfcamp horizontal drilling program. We placed 69 wells on production in that field during the second quarter with continuing strong performance. 37 of those wells benefited from the Version 3.0 completion optimization.

Continuing to see and realize significant capital efficiency gains in the Spraberry/Wolfcamp longer lateral lengths, greater optimization program, continuing to enhance well productivity. Continuing to see costs coming down on a per lateral foot, which Tim will talk about. Again, a great achievement.

We are continuing (technical difficulty) to see production cost per BOE by 26% from first half of 2015 to first half of 2016. You'll see Rich talk more about it and also Tim, but what's amazing to me is that the horizontal well operating cost, excluding taxes, is down to almost $2.00 per BOE. So definitely we can compete with anything that Saudi Arabia has.

A lot of people are asking why, with the deep inventory, why we are acquiring 28,000 net acres in the Midland Basin from Devon for $435 million. It's simply because it's totally integrated among our acreage. We did not want somebody to come in. Most of the competition couldn't bid on this because they couldn't get longer laterals. We had it totally surrounded, allocated $14,000 per acre and what's interesting right after we made the announcement on the acquisition, somebody is paying $58,000 per acre right next to this acreage. Closing expected in the third quarter. And you'll see from some of Tim's slides, this is the best area in our horizontal B Wolfcamp area. Wells will be between 1.5 million and 2 million BOEs.

Going to Slide number 4, the Company plans to increase its horizontal rig count that we announced already from 12 to 17 rigs in the north during the second half of 2016, first rig in September followed by two rigs in October and two more rigs in November. Three of those rigs will be dedicated to the Sale Ranch area once locations are permitted.

We already talked about a slight increase in capital expenditures, about $100 million to $2.1 billion. And again obviously is it takes us a good 130 -- 125 to 135 days to bring wells on.

Production, we won't see any production until 2017. But we are increasing our 2016 production forecast from 6% to 12% to 13% plus, again due the higher forecasted growth rates from the Spraberry/Wolfcamp well productivity.

The 2017 rig activity expected to the production growth ranging from 13% to 17% in 2017, again funded by a strong investment-grade or really the best balance sheet in the industry, a strong derivative position and forecasting cash flow assuming mid-July strip prices.

This last comment before I turn it over to Tim is probably what's most important in this whole slide deck. The Company expects to deliver compound annual production growth of 15% and maintain debt to operating cash flow below 1 during 2020 at mid-July strip prices.

Now, what's most important is that the strip price of 2017 to 2020 has only dropped about $2.00 to $3.00. So what's happened obviously, the front month has dropped about $10 from $51, $52, down to $42.

So obviously we get asked all of the time do we have any plans to reduce our rig activity? The answer is no. This long-term forecast is Version 2.0, so it doesn't have any upside from 3.0, doesn't have any upside for further cost reductions or optimization improvements. And even though we could talk about it, but the Company is well on its way to growing 15% well past 2020. We expect to spend within cash flow in this plan once oil prices gets to $55. That could be in 2017. It could be in 2018. It could be in 2019. We are using 2018 here. That's also what's amazing to me. So I prefer long-term that the strip stays where it is, somewhere in the $50 to $55, because Pioneer can outperform every independent, especially the large-cap.

I'm going to now turn it over to Tim to give you more detail on the CapEx.

Thanks Scott, and I'm turning now to Slide 5. The capital spending program for this year remains intact. As Scott already mentioned, we did have to increment the D&C component to $2.1 billion, another $100 million or so to account for the five rigs or so that are going to be added here in the second half of the year.

Pad drilling, as he mentioned, will have the effect of having this not impacting 2016 production, but rather it will start to come into 2017 when we add new production from these rigs.

Essentially, rather than going through the details in this slide, I would simply say all other capital items remain essentially the same for the year. And they are easily funded by our cash on hand and improving operating cash flow as we see commodities improve from here on out.

Turning to Slide 6, we've updated our production guidance going forward. It really simply reflects several consecutive quarters of outstanding performance from the wells. And this is the third in a row I think we could say so.

Looking first of all at the quarter, Scott already mentioned we substantially beat our production guidance range at 233,000 BOE a day or so. And the result of that of course is bumping the year-end -- the year total production rates up to about 231,000 BOE per day. Again, just tweaking it up by virtue of the most recent results.

Third quarter we see essentially flat or slightly up in terms of production. There's a lot of mechanical reasons for that, but some of them have to do with the fact that we're going to lower the number of wells we put on production in the third quarter compared to the second quarter just by virtue of the schedule. We are currently planning to pop 50 wells in the third quarter versus 69 in the second quarter.

We have a larger number of offset wells in this particular upcoming quarter that will be shut in waiting while we are fracking nearby wells and had been the case in the second quarter. And then in addition to which we are seeing longer periods of utilizing chokes to reduce water flows in the early life of the wells to make sure we don't overburden our facilities. All those are just coming in 2016's third quarter. 2016's fourth quarter looks exceedingly strong. So this is just simply a scheduling related matter that has this effect.

Finally, as a result of what Scott had mentioned with the five rigs that we are adding, and if those are maintained through the balance of 2017, that will yield a growth range of 13% to 17%.

And finally, if you look at the most right-hand bar, our internal data shows that we can generate that 15% CAGR just by adding a few rigs per year over the period 2018 through 2020. And as he mentioned, it does not include anything other than Version 2.0 completions, and does not include anything in terms of further efficiency improvements. I think this growth trajectory is very doable from an operational standpoint, and we plan to execute it accordingly.

Turning now to Slide 7, the recently announced acquisition I feel like is very opportunistic and it has the effect of further high-grading our portfolio with some of the best acreage in the Midland Basin. The 28,000 acres or so in the Midland Basin are such that their spread from Sale Ranch all the way down into Northern Upton County, but the main focus and the main reason to this was focused on the Sale Ranch acreage where we are adding about 15,000 acres, as shown on the map in the black circle. This is the area we've drilled essentially our most productive Wolfcamp B wells. You can go out on the Railroad Commission site and find this out for yourself, but this is where we've made really simply outstanding wells. I've got a graph to show you the results of those wells coming up.

What this transaction does is add 70 long laterals in the Wolfcamp B at high working interest. Each of those wells we feel like based on the return metrics look today at $10 million worth of NPV, so right there that translates into $700 million of value just in drilling those locations, which goes to show you I feel like the economics of this transaction are really outstanding. It also adds other locations, about 80 Wolfcamp B locations, that would have lower lateral lengths -- or lower working interest. We need to go to work on these areas by declaring additional interest as well as potentially trading acreage to increase the length of those laterals. But we have been very successful on that, and would expect to be successful going into the future.

The 13,000 acres principally you see in the South would be used as trades to further consolidate our own acreage and allow longer laterals to be drilled. But people do ask us all the time, does this transaction, does this signal that we might do more of these type of transactions?

The first thing I would say is opportunities like this don't come around very often that would accrete value to our existing portfolio of acreage. However, you never say never. But the more frequent deals you will see us doing will involve the trading and consolidation of acreage that I mentioned a minute ago in order to drill longer laterals. In fact, since the early part of 2015, we've traded 19,000 gross acres and have acquired 3.2 million gross lateral lengths in terms of feet for no cash exchanging hands. So, this is where there is huge value-added and you will see us continue to be heavily focused on improving our lateral lengths by virtue of these trades.

Going to Slide 8, this is the Sale Ranch data I mentioned a minute ago. We are across all of our acreage of course continuing to build on our success when it comes to completion optimization. But first for the Sale Ranch, this is the main focus of course with the Devon transaction. Over time in this field -- this area of the field, we've placed 41 Wolfcamp B wells on production. That's over the last two years. That's wells that are over 7,000 feet. The graphs kind of show the performance of these wells.

The first 16 or so wells were almost all Version 1.0 completions. And you can see that they in the gray line are indeed above the 1 million barrel type curve, but not significantly. It's when you start looking at the 23 wells performance in the blue where you're starting to see the benefits of optimization. Many of these wells that -- of the 23 were subject to Version 2.0 completions. And you can see, as a result, these wells on average are exceeding that 1 million barrels type curve by about 60%.

And then finally, when you look at the most recent long lateral wells, these are wells that are on average 11,000 to 13,000 feet in terms of lateral length, these are phenomenal wells. We only have two those wells currently on production, but nonetheless you're looking at wells that look like they are about 2 million barrel wells, at least in terms of early-stage production. So I think we are very confident in this area and we've drilled a lot of wells in the area and that's why we think the Devon transaction accretes such great value to us. And as we learn and continue to refine this completion optimization in the area, I think this Sale Ranch acreage is expected to show very strong results going forward.

Then on Slide 9, this is more granularity, especially on completion optimization in the Wolfcamp B. This is both in the north and the south. You'll notice that the graphs show some early results, about three months of results or so, on Version 3.0. First, in the north on the top part of the slide, you can see that we had about 14 wells that were subjected to Version 3.0 style completions. The first 45 days or so of that data really needs to be tossed out as N/A simply because, during the period of our choke management, it's not unusual now to have some wells choked for two months just as we await the ability to handle the significantly increased volume of water being pumped into these wells. But if you take a look at the Version 2.0 results, they are outstanding of course, probably a 35% improvement over the 1 million barrel type curve. But we are looking forward to see the fruition of all the Version 3.0 wells. You can see we've had the wells we put on production only on production without being choked back for about a month. So they are starting to show results that exceed the 2.0, which is what we expect. And those results I feel like are encouraging so far. You have to stay tuned as we get more data over the next couple of quarters.

We are seeing similar results in the southern JV area where you have a mix again of Version 2.0 and 3.0 wells. And the graphs look essentially the same. We don't see quite as much pickup here in the Version 2.0 case of about 25% in the south. It's just a product of less pressure as the further you go south. But nonetheless we still are encouraged as we look at the 3.0 line, again a situation where the early part of the well was choked that we are now starting to see peaking above the 2.0 line. And we will be really interested to see how this works out. But I think we'll know a lot more over the next couple of quarters about what Version 3.0 can contribute on a per well basis, but suffice it to say these early results are positive.

Now, turning to Slide 10, here we are talking about completion optimization in the Wolfcamp A. The Wolfcamp A of course is zoned where which we have not drilled nearly the same number of the large sample size of wells compared to the B, but we are showing similar style results. Wolfcamp A early day 2.0 wells now after having been on production in some cases almost as long as a year have shown about a 25% productivity improvement while the 3.0 wells are in a similar position as was seen in the Wolfcamp B. That is early days just completing their choke management period.

In the Southern Wolfcamp area, there's only been one oil well drilled. You can see it looks like a roughly 1 million BOE type curve. We have not yet done any 3.0 style wells in the south for the Wolfcamp A.

But based on all these results that we've begun to see for Version 3.0, we are evaluating whether to expand the current 80 well campaign to a larger number of wells as we add rigs here in the latter part of the year and into next year. We'll be getting back to you with more details on exactly how many wells we are going to expand that to as the team completes their work.

Turning to Slide 11, this is Lower Spraberry Shale data, just to update you on that. You can see that all 24 wells are shown. We've drilled with 2.0 versions style completions. They still show about a 10% improvement over the 1 million BOE type curve.

I think the takeaways from all of this, these slides, are significant in the sense that we now have 150 wells with Version 2.0 data and we can pretty definitively say that's going to be the new style completions at a minimum. We have this 80 well campaign going. 37 of the wells of the 80 are on production with various styles of Version 3.0 optimization. They are looking good, but we have to see more time before we can really tell you definitively how good they are going to be.

Choke management of course still impinges upon our ability to see early well production results. But I think it's the case that not only will we put the 43 additional wells on using 3.0, but we will look at actually increasing the size of that campaign as we get into the latter part of this year and into next year.

Slide 12, turning to cost efficiency, Scott covered some of this, but I'll try to be brief with it. But suffice it to say that, even with more sophisticated and costly completions because of going from Version 2.0 to 3.0 during this time period where the costs are higher as a result of that, we have continued to more than offset that cost increase and continue to drive down overall D&C costs. You see here over the last year and a half or so, we've had a 35% decrease in our D&C costs despite the fact that we are adding costs, and not insignificant costs, when we are doing Version 2.0 and 3.0 completions. There are a lot of reasons for that.

You may recall last year we ended the contract for both our tubulars and cement pricing, seen some substantial reductions this year, probably 30% to 35% reductions.

We also see continual completion efficiency gains. One way to do that is to reduce our nonproductive time where we just simply reduce the number of days on the jobs, and that reduces all the costs that are driven by time, including things like rentals, supervision and labor. So we are seeing a lot of improvement when it comes to that area of the business as well, but we have room for further improvement.

Our rig rates today are still based on the old contract rates and will start peeling off as we get into 2018, 2017 and 2018, where we can then expect to see spot rates for rigs which we've been waiting for for some time.

I'm going to turn now to Slide 13, give you some details regarding the Spraberry/Wolfcamp drilling campaign as it proceeds. It's really on pace other than for the adding of the five rigs coming up here in the next few months. Expect to place 230 wells on production. You can see the splits there, still predominantly Wolfcamp B and to a lesser extent Wolfcamp A.

We believe, as I mentioned, that the 2.0 style completion is now essentially the standard design, but we'll know a lot more about 3.0 as we go. But we reduced our D&C costs to about $7 million. That's assuming a 9,000 foot lateral, and the combination of the new completion techniques.

Really importantly, and Scott alluded to this, is our production cost per horizontal well is really coming down nicely. Even last quarter, we were talking about this ranging from $5.00 to $7.00 per BOE, which includes both LOE and taxes. Now we see that at $4.00 to $6.00 per BOE. This is a product of gas lift being used in most wells, and doing a lot of work in terms of centralizing maintenance and reducing labor costs, the result of which is very high IRRs even though we are in this price deck that we face, in this case $50s, low $50s, and gas really in the low $3.00s. But the fact is we have been able to reduce our costs and improve our efficiencies to the point where these wells still are highly economic. And I think we would say that to the extent that we get upside on Version 3.0 and/or any improvement in commodity prices, those returns only improve.

Turning to Slide 14, my last slide, this is a slide showing how all this translates into production growth. We did have a tremendously good second quarter. This is specifically in the Permian Basin, 167,000 BOE per day. That allows us to bump the whole year up to an average of 168,000 just by virtue of that early good performance.

We did put 69 wells on production, the vast majority of in the northern area. We are completing the southern area wells. We'll have those mostly done here this quarter.

And we did complete more wells that had been planned, pushing some completions from the third quarter into the second quarter. That number is lower as we get into the third quarter, as I mentioned, about 50 wells to be put on production.

And then to the extent that we have shut-in volumes from offset fracs, this is where we shut in wells next-door to wells being completed, that number is going to be about 35% higher as estimated compared to the second quarter. All of those lead to the notion that the third quarter will be more flattish than we would have expected compared to the second quarter, but it has to do with all these reasons, including the curtailing of wells with choke management.

So, overall, I would say this was a very strong quarter operationally. And I think that's just the theme going forward as we should see outstanding results from these assets in the future.

And with that, I'm going to pass it over to Rich for a review of the second-quarter financials and the third-quarter outlook.

Thanks Tim. I'm going to start on Slide 15 where we reported a net loss attributable to common stockholders of $260 million, or $1.63 per diluted share. That did include non-cash mark to market derivative losses due to the higher commodity prices at the end of June versus the end of the first quarter. So those losses on an after-tax basis totaled $231 million or $1.41 per diluted share. So after adjusting for the mark to market losses, we were at a $37 million loss for the quarter or $0.22.

If you look the middle of the page where we show the results for the quarter versus our guidance, you're going to see that production is (inaudible) mentioned was very positive. Our cost initiatives are bearing fruit and coming down. So we are on the positive side of guidance on a number of these things or within guidance, so really an overall exceptional quarter financially.

One other point to mention is that we had just under $410 million of operating cash flow for the quarter as well.

Turning to Slide 16, look at price realizations. On the bars there, you can see that oil prices were up 47% to $41.43 for the quarter, albeit off of a low reference point for the first quarter. NGL prices were up 38% to $14.21 per barrel, primarily with higher ethane and propane prices that we experienced during the quarter. Then if you look at gas prices, they were down 7% although we did see gas prices jump towards the end of the second quarter. So we hope the third quarter will be better than the first and second quarter.

If you look at our oil price differential for the quarter, it was down $1.20 from where we were in the first quarter. That's really from the two things, and I think we mentioned these in the first quarter call, was, one, our Eagle Ford condensate contract. We had a new contract that was effective April 1, so that reduced our differential on Eagle Ford condensate, so that helped on that front. And we also saw tighter Midland cushion differentials for the quarter.

Looking down the bottom, you can see the impact of our derivatives. We still had a great quarter from a derivative standpoint, $132 million added in cash flow during Q2 from derivatives, and brings our total to $349 million through the first six months of the year.

Turning to Slide 17, look at production costs. Once again, Tim talked about it, but the asset teams are really doing a great job on lowering our cost structure and improving our margins. You can see there, in the second quarter, our production costs per BOE are down 9% from the first quarter. Base LOE is down about 5% due to centralizing our maintenance, the cost initiatives that the asset teams have going on. We're reducing our saltwater disposal handling costs. Labor costs are down as we are really covering the increased activity with the same headcount. We're using gas lift versus electricity -- or submersible pumps on to support our well, and lower fuel and electric costs as well.

The other thing that you'll notice here is when you look at our third-party transportation costs on a per BOE basis, those are down. It's really due to our declining Eagle Ford production, which is the bulk of our transportation costs. And so on a weighted average basis, as the Company continues to grow and it becomes a smaller portion of it, you'll see that go down on a per-BOE basis.

And then probably lastly, as Tim also talked about with the Spraberry horizontal Wolfcamp wells coming in and their low operating cost of $2.00 to $4.00 before taxes and $4.00 to $6.00 in total, on a more weighted average basis, production costs will continue to benefit from those wells as we add more to that production in the future.

Turning to Slide 18, which really sums up the last two slides from a margin standpoint, a new slide that we've added, it really highlights why we have 90% of our capital budget focused on the Spraberry/Wolfcamp and why we are comfortable adding rigs going into the future. It's really tremendous that its cash margin in the Permian horizontals are more than twice of any of our other assets, and the low operating costs that Scott talked about really just drives the great returns that we can generate from these assets.

Turning to Slide 19, look at our liquidity position, an excellent position, probably the best in the industry today with a net debt at the end of the quarter of $300 million and an undrawn credit facility of $1.5 billion. At the end of the quarter, we had net debt to forecasted cash flow of 0.2 times, so just a terrific financial situation for the Company as we continue to invest in these horizontal wells to grow our production and generate great returns.

If you look at timeline in the middle there, you'll see the 2016 debt maturity. That was actually due in mid-July, so that was paid with cash on hand. We also have a maturity that's due in March of 2017, and that also was prefunded with the bond offering we did last December and we paid off with cash on hand as well.

Turning to Slide 20 and really focused on third-quarter guidance, daily production 232,000 to 237,000 BOEs. As Tim just recently talked about, it is primarily flattish for the quarter, up a little bit due to the reduced wells that we are going to place on production during the quarter and then the offset wells that will be shut in as we frac those wells during the quarter.

Production cost at $8.25 to $10.25 per BOE really reflects the lower run rate and the efforts of the asset teams to continue to bring those costs down. The rest of the guidance is consistent with second-quarter results and prior quarter guidance, so I won't go through those in detail, but they are there for your review.

And so, with that, Rachel, we'll go ahead and open up the call for questions.

(Operator Instructions). John Freeman, Raymond James.

On the big cost reductions that you all had during the quarter despite the bigger completion jobs that you're doing, you mentioned some of the things that drove that in terms of efficiency gains and just some less downtime. But anything specific that you could point to make just such a meaningful change in just a quarter?

Of course, we are seeing some of the cumulative effect of things we've done in the past as well. In other words, we are just now to the point where we would say we are full run rate at lower tubular costs as well cement costs, as I mentioned. Of course, it took us a while to burn off inventory from what we had at the end of last year. So now we are at a run rate which is just reflective of spot pricing, which is very low compared to last year. But there's really a lot more of the same is the way I would couch it.

I know we've very substantially reduced our nonproductive time completions, which, as I mentioned in here, I think our nonproductive time was down about 52% in this particular quarter and it has to do with all aspects of the completion, so it has to do with reducing time on the wireline res as an example, reducing mechanical failures where we can. And when you start reducing nonproductive time that substantially, it has a very positive effect on things that we get charged on a daily rental basis. I think, for that matter, it's supervision. You're not on the job as long. You don't need labor out there. You don't need any transport. You don't need a lot of things for as many days as you did before. So those are very much cumulative effects. And then in essence what happens is you just have the effect of offsetting the fact that completions are more expensive.

Great. And then my follow up question, when you talk about the 2017 and the longer-term guidance, and you mentioned that it basically reflects like the 2.0 Version but not Version 3.0, I'm just curious. Like when I look at like the Version 2.0 impact on the Wolfcamp A and B, kind of 25% to 35% improvement over the type curve, does the longer-term guidance like fully reflect 2.0? Is it some sort of a risk kind of case of what you've seen on the 2.0? Is there still some additional upside just based on what you are already seeing on 2.0 before we even talk about Version 3.0?

This is Frank. I'll try to answer that for you. I think it's fair to say that it is in that 25% to 35% range, but we tend to be conservative, particularly in areas where we haven't drilled ye. Obviously, going forward, we will be going to areas as we expand out of our current drilling areas. But generally, we have assumed Version 2.0 type results. 3.0 would be an upside. And I think as Tim mentioned, when you look at the capital spending and what our costs will be, that our costs right now reflect what we've done to date. We haven't baked in any additional efficiencies, even though I would tell you that I think the teams are very focused on improving further.

That helps. Thanks again guys. Well done.

Doug Leggate, Bank of America.

Good morning everybody. Scott, I know we are going to see each other later in the year, but congratulations. We're looking forward to seeing what happens next with the Company post your retirement.

I think my question really is a follow-up to John's on the medium-term guidance. Is it kind of an activity level, meaning like a rig trajectory, that you're using to cap your assumptions? I'm really trying to understand what the constraints are. $55 oil is obviously fairly modest I think by most people's long-term expectations. So, what happens if oil prices are substantially higher than that? Let's assume $65, $70. What would Pioneer look like there?

I think, well, it's amazing to me that we can achieve 15% production growth up to 2020 in an average $52 to $53 oil price environment. And obviously, in a $60, $70, $80 price environment, the Company will have to bring forward more of their locations and the growth rate is going to be that much higher. What you've got to factor in, though, is what's going to happen to the service cost. And we saw what happened in 2014. So that's why I said personally looking at the model, I would rather oil stay and $50, $55 range and keep costs in check, as a large shareholder. And so but obviously as a -- if Tim and the Group have a lot of excess cash flow, then they will bring forward more and more of those 20,000 locations.

Maybe as kind of an infill question to try and frame out what I'm really trying to get at is obviously there's been a lot of chatter over the last three or four years about what the infrastructure implications are in addition to the drilling capital and so on. And obviously that became a focus issue a year or two ago. So that's kind of what I'm getting at. What are the constraints over the activity level? How would you choose to move forward? Would growth be the top priority, or in a $10 higher oil price environment, would you choose to do something different?

The way I would couch it would be, in a $10 higher oil prices environment, number one, our cash flow is dramatically higher, which would enable us to spend more and still be within cash flow in that period, let's say 2018 to 2020. So I would say we want but the rigs to work to do that, to utilize that capital to the extent the returns are as good as they are today even at lower prices.

Right now, we have baked in adding three to five rigs per year in sort of the 2018 period, 2017, 2018, 2019, probably in that range. And when we do that, we have dramatic growth increases that we've already shown you.

I think if you look then at what you would do to the extent you're higher than that, we can actually put more rigs to work out there than three per year. That's clear. There's a point at which we had 45 vertical rigs running in the Permian Basin at one time. So I think we can actually physically get this done. I think it's just a matter of deciding how much of this PV do we want to bring forward. We certainly have the cash wherewithal to do it, and I think it's just a matter of getting boots on the ground. We would have to spend more on infrastructure. That's clear. Right now, we have baked into our internal modeling $250 million to $300 million a year of other PP&E for just that. We would eventually bump into the need for expansion of our sand plant at that rate, and that would probably be a 2018 or 2019 scenario. We would probably also be in a position where we would want to add another gas plant out there in 2018 or so if that were to occur just to deal with the additional volumes that would come from a more accelerated campaign.

So in the water system, of course it's pretty clear that we are building out a substantial water system for a higher rig count than is there today. We might need to accelerate some of that spending. Of course, that's we feel like going to pay out really well in the long-term. So there is more of the above that we would need in terms of infrastructure. Of course, in a higher cash flow model, we would be prepared to fund all that.

I've taken up enough time. I'll let someone else jump on. Thanks.

Pearce Hammond, Simmons.

Good morning guys, and congrats on a great quarter. So, my first question is do you think, being vertically integrated provides you a competitive advantage in the beginning of a cycle when all producers are seeking to increase activity? And to pick up a little bit on Scott's comments for sort of a preference for $55 where you guys can grab share at other producers' expense, I mean do you think you have better service cost price insulation than other producers because of your vertical integration?

I think that's definitely the case, Pearce. If you look at the immediate advantage we have is when things improve -- today we only have five of our seven fleets working essentially full-time. When things improve and/or maybe to get back to Doug's case where we have $10 higher oil, we start adding rigs, we've got two fleets that are ready to go and we would be at the point where seven fleets could handle a higher rig count.

The issue the industry is going to face in terms of getting warm bodies out into the field is a substantial one. And we are, by virtue of this vertical integration in public services, 100% insulated from that. So we can go to work immediately when we are ready to accelerate and not have to stumble around and find people to go operate our facilities and our equipment. I'll say the same thing about our sand business.

We have ready sand available, especially after we expand, to meet a substantial amount of our needs. So we don't have to be dependent upon when things get crazy on sand of having to haul in a bunch of white sand from Wisconsin. It will be, in that scenario, twice as expensive as local Brady sand.

So I think as we emerge from the downturn, I think we are actually better prepared because of vertical integration than not. That said, we are not making any money at vertical integration now. That's clear. That's true of all the service companies. But we will also be protecting ourselves in terms of rate increases going forward by doing almost -- or a substantial amount of that work ourselves.

Thank you for that Tim. Then my follow up if I thought Slide 18 in your presentation deck was very illuminating as it illustrates the very low production costs for your Permian horizontals. Just curious why your Eagle Ford production costs are so much higher.

It's mainly the -- the biggest component, as I mentioned, is the gathering and transportation down there, so that basically is around $6.00 a barrel for condensate and mid-$0.60 for gas.

Great. Thanks so much.

Evan Calio, Morgan Stanley.

Good morning guys and congratulations to both Tim and Scott. The two new elements that I see in the presentation really are the cash margins per play where horizontal Midland is a standout, and the reintroduction of this 2020 growth within cash flow at low leverage. Is the message here really to emphasize your differentiated growth profile is achievable without issuing additional equity, at least on the strip? And in disclosing the horizontal Midland cash margins, do you see that as an indication of material corporate return improvements as those Midland 2.0, 3.0 become an increasing mix on production?

Yes, that's definitely the case. That's the main point we are trying to make, that we can live within cash flow, keep a great balance sheet, don't need to issue equity, don't need to sell assets.

And maybe a follow-up there, how do assets fit into this longer-term outlook? Future sales for the Eagle Ford or less core Midland would appear to bolster both those elements, both returns from the cash margins that you disclosed as well as -- I mean, clearly, it would reduce any funding needs.

As I've always said the last several years, in the Company, all assets are up for sale at the right price. And if somebody offers us a great price at the right time, the Company will always look at it and redeploy that capital into the best performing assets.

That makes sense. One last if I could. On the growth guidance, I know you have one times leverage. Is that commodity dependent, or is that something you would target longer-term regardless of where oil prices ultimately trade?

As we've said before, it's going to be -- we are going to drill based on returns, and so it will depend on where commodity prices are. We are going to always do returns but based on where the strip is, we are very comfortable with the program that we have in place.

So that could increase is I guess what I'm trying to understand.

I think, as Tim said, yes. If we saw a $10 increase in commodity prices, then, yes, it could increase to use that cash flow for high return projects.

Great. That makes sense. Thanks guys.

Paul Sankey, Wolfe Research.

Hi guys. Thanks. A long-term one and a short-term one if I could. Scott, I will go to your first for the long-term. In the past, you've talked about I think as much as a $100 billion need to develop your own acreage. I think the time frame was 2025. You've gone through quite a lot of detail on the outlook to 2020. Given what you were saying about the length of your career, could you just think forward for us into the very long-term about how the Permian has developed and where it sits and how much Pioneer is going to have to spend in order to do that? Thank you.

Yes, I am giving a -- I don't know when it's going on the website, next week, that slide deck, but I am speaking to 3,000 engineers and geologists in San Antonio talking about the Permian. So there's an interesting slide deck that will come out next week in that presentation.

But my firm belief is the Permian is going to be the only driver of long-term oil growth in this country. And it's going to grow on up to about 5 million barrels a day from 2 million barrels, even in the current strip, a $55 price environment. So it's got the best rock, obviously the best margins, and it will provide essentially the only growth long-term. The stack play and the scoot play, maybe the Niobrara will do a little bit, but the Bakken and the Eagle Ford I think are -- there's no way they can recover to the levels that they've already had. So that's why I am confident the world needs the Permian, the Permian is going to be the future of the US and help in world supply.

That number that you've made, I may have misquoted you and I apologize, but did you had sort of $100 billion kind of number that you talked about for Pioneer alone?

We still show it. Just take the well costs, $7 million times 20,000 locations. That's $140 billion. It's an easy number to get to.

Got it.

This is Frank. The good news is it's actually coming down from where it was before.

That was somewhat why I was asking Scott, because obviously this is a shifting dynamic. And yes. I look forward to looking at the presentation.

The short-term question is just how rig rates and how your contractual structure is changing. Is there anything to add on whether those costs are coming down as you roll off contracts and how are you reshaping contracts, anything you could add on that? Thank you.

I think the current rates that we understand are being marketed up roughly $14,000 per day in terms of rig rate. Our contracts typically, if you look at the things we signed over two to three years ago that were intended to deal with a higher price than we are dealing with today in terms of commodities, we are struck at roughly $25,000 to $26,000. So I think there's a dramatic improvement in the weighting for us. I think the fact is that a lot of those rigs don't come off until as we get into the latter part of this year and particularly into next year. So next year is when we are going to start seeing peeling off of existing contracts and then starting to revamp the platform of the rig campaigns at spot prices.

Thank you.

Brian Singer, Goldman Sachs.

Thank you. Good morning. And Scott, congratulations on the retirement. And Tim, congratulations as well.

Given the higher water needs as you move more towards Version 3.0 completions, can you give us a little bit more detail as you mentioned water infrastructure a bit earlier from a higher oil price acceleration perspective? Can you give us an update on water infrastructure plans, capital -- how capital could evolve there in 2017 and 2018, particularly if you do move to 3.0 completion? And would that open the door at all to changing the managing of chokes to opening the choke down the road?

You've got two or three questions built in there. I would say that we have a big multiplicative effect going on right now because, in combination with wanting to pump more volume of water per foot, we are also increasing average lateral lengths. So the amount of water we are pumping has gone up dramatically. It's easy to calculate. In some of these wells, it would've gone up roughly a third compared to where it was done in the past. And we are already pumping quite a bit of water.

So I think the answer is water is going to be a key. I think we had that identified even a couple of years ago, as you recall, when we talked about building out at that time what was a massive water system. In response to the downturn, we have curtailed some of that spending and postponed it. But there may be a day of reckoning for that as we move forward, especially in the scenarios of higher prices.

But suffice it to say, we are taking water from the city of Odessa -- this is effluent water -- as we speak. We still plan on an agreement with the city of Midland to do the same. That contract with the city of Midland has us investing capital in their water infrastructure.

We are spending money this year on some of our mainline systems, but we would want to do further work on our main lines and some of our secondary storage systems, basically frac pumps, as we move forward. I think we can do it on a relatively piecemeal basis, but as I said, as we are pumping higher volumes, it becomes more problematic in terms of just volume needs.

One thing we are doing is trying to get the course to where we are not using any freshwater. We are making big strides right now in expanding our recycling programs so to where we can get there I think in a matter of a couple of years to where we are not using any freshwater.

We are doing a lot in terms of drilling new saltwater disposal wells on the one hand but also water -- this is brackish water sources. On the saltwater disposal front, you get kind of the other side of the coin, which is to say this water, when you start turning the wells off for production, comes back to you. We are pushing more water down in the system of another completion of how that water comes back, and you've got to have a place to put it.

Rather than overbuilding the facilities at the least -- this is tank batteries for saltwater production, which had been, generally speaking, designed for lower volumes, now we've got dramatically higher volumes of water -- this is produced water coming back at us -- rather than overbuilding the infrastructure, and in doing so basically creating a situation where you will never be able to use the peak capacity, w. Would rather choke these wells back. In some cases, they have been choked back for roughly only a couple of weeks. Now we are seeing, in some cases, you just saw in the data I showed you 45 days or to 60 days. And when the water starts coming off the system, then you get to a point finally where the facilities can handle it. So, I think we would rather err on the side of not overbuilding facilities and just gradually put these wells on production than the other side of the coin.

That's really helpful. And if there is a day of reckoning just based on the increased water needs down the road in Version 3.0, is there still room on the balance sheet from the equity offering of a couple years ago for that expansion, or would that be something that would be kind of incremental as a major infrastructure project?

I don't think we have anything we would look at and say, wow, this is going to blow the doors off the balance sheet from the standpoint of cost requirements for infrastructure. To use an example, our Midland contract probably will roughly require $100 million of investment. We are spending $50 million to $100 million probably every year anyway on the water systems. That's not that substantial.

You look at gas processing facilities, typically, in our case, they run $140 million or so. We have 27% interest, so that's not very material. So I think you'll see us still go about it in somewhat of a piecemeal fashion, considering we are not at a point where we were in 2014. In 2014, we were forecasting going from 25 rigs to 100 rigs over an eight-year period let's say. Today, we are at 12 going to 17 and hoping to go to 30 over the next three years or so. So we are really not in the same scenario we were in. But nevertheless we are pumping more volumes, so there is that affect. But it will be something we have to continually spend money on, but I think we'll still do it more piecemeal. You're not going to see us coming out with a huge multi $100 million water project any given year.

That's built into our five-year plan too, so we factored that in when we were talking about the five-year growth profile.

That's helpful. Last quick one, how close are you to actually taking the EURs up based on Version 2.0, or are you still waiting and watching?

I'll answer that. This is Frank. I think if you -- I got this question last night from one of your analyst brethren. I think, when you say taking the type curve or the EUR up, I think we pretty much signaled that when you look at the performance on our wells, the 25% to 35% type improvements, we're basing our forward program on that. So however you want couch it in terms of taking the type curve up, I think we've signaled pretty loud and clear that we are comfortable with the performance we've been seeing and we expect to see it in the future.

(multiple speakers) I was just simply saying we now are saying that 2.0 is the standard.

Thank you very much.

Charles Meade, Johnson Rice.

Good morning Scott, Tim, and to the rest of your team there. If I could, I'd like to go back and ask one more question on that compelling data point or stake you guys put in the ground about 2018 and being able to grow -- keep the growth rate at 15% while spending within cash flow at 55%. What I'm curious about is, if you had done a similar analysis, or a similar scenario, back at the beginning of this year, say six, seven months ago, what would that -- what would the oil price have needed to be then to get that same 15% growth rate? And do you have a sense of whether the biggest gains are behind us, or are perhaps still in front of us?

I think suffice it to say we were looking at 60% or 65% case to be able to achieve the same type of scenario we are looking at here, if you look at it a year ago or so. And all we are really saying is our model now has changed dramatically. So in this sense, regardless of commodity prices, our cost levels have come down, our productivity has come up to the point where the old 60% to 65% is basically now 50% to 55%. That's what we are saying. And this is from data. This isn't just from smoke. This is from the well results we see and the costs we have been able to achieve. And so that's how I would answer the question.

And any thought on the size of what's left in front of you, or that's just the unknown and we will find out when we get there?

I don't know. I don't know how to answer to that. I guess the question is, going forward, we can actually grow at almost any rate we want to. It just depends on how much capital we want to put to work.

Got it. Thank you Tim. And then my follow up I guess dovetails big with Brian's question earlier. As you've changed this completion style, as you've gone to not just longer laterals but more water per foot, that sort of thing, have you had to -- I think you've already answered this, that you've decided you're not going to change your surface facilities in response to that. But I'm wondering. Is there -- is that the correct read and is there a trade-off implicit there between, if you are going to keep your surface facilities the same way, that you're going to have to wait longer to learn what you would've learned earlier with (multiple speakers)

Yes, so I think there is a trade-off. I think I mentioned that, Charles. There is a trade-off that has to do with not overbuilding when you only -- we see this all of the time in gas prices as an example, where you build a gas plant and if you're not careful, you build it for the capacity that exists one day and you see producing production declines, and you only use the capacity you built out like extra cost for a minimal amount of time. So there's this trade-off between over-capitalizing a project, and/or the need for current production.

I think we're in the range of 30 to 40 or 45 days in terms of choking the wells back. That's really immaterial. It does postpone our knowledge base for whatever that is, 30 days, but we really need six months or so anyway of production data to figure out how these wells are going to do. So we are not that worried about postponement of 30 days of knowledge. I think that's doable, that's a reasonable cost of the trade.

Thanks Tim. That's good detail.

Ryan Todd, Deutsche Bank.

Thanks. Good morning gentlemen. Maybe if I could ask, maybe starting off with a question on long-term kind of, again, another longer-term development type question. As you eventually turn to a more holistic development plan across multiple horizons, I guess the idea of developing effectively a large three-dimensional cube is a (technical difficulty) one, one or two horizons at a time. Any thoughts on what you may be able to capture in terms of capital efficiency longer-term via the more efficient use of surface infrastructure and so on?

Yes, the way I would couch that would be, first of all, as you know, we have it as a sort of a goal to drill a series of Wolfcamp B wells then come back on delayed A's in the Wolfcamp. So that's a systematic approach we are taking. That means we also need to come back later on, for example, Lower Spraberry Shale zones and so on.

But in terms of -- as you look at the capital requirements of all that, what we do know is when we build (inaudible), they are for 60 wells essentially. So the cost efficiency comes especially on the last let's just say half of those wells. The first set of the wells will be subject to several million dollars worth of capital just to put the facilities out there. The last wells are subject to $150,000 of capital because the fact the facility is are already there and we have to just put in some production equipment. So you actually do see improving returns if you look at simple identical well metrics the further you go into the program. We are building for the future. What we are saying is we don't want to overbilled for the future.

All right, thanks. That's helpful. And then maybe on lateral length, do you have a view at this point of what the sweet spot is in terms of lateral length? You've gone as long as 12,000 feet. Is it the longer, the better? Is there a trade-off at some point that you've seen between lateral length and completion risk? And then maybe as a follow-up to that, what percentage of your overall northern portfolio is conducive to I guess 9,000 to 10,000 foot laterals?

The answer to that question, the last question, is about 60% would be amenable to 9,500, 10,000 foot laterals today. We are building that inventory up, as I mentioned, vis-a-vis trades and in other methods to make sure we can increase the lateral lengths.

But as you look forward and you look at what lateral lengths seem to be optimal, our average in the Wolfcamp B I think this year has now been edging up to 9,500. I wouldn't be surprised to see that number go up from here just on the basis of what I just mentioned. However, there's probably a limit at which we would call it a day on horizontal length, probably in the neighborhood of 13,000 feet, maybe a little bit more than that, just based on what amounts to hydraulics. You have a lot of line losses as you pump volumes down that long of a horizontal pipe, and so the risk you have is not getting off proper fracs, especially the toe of the wells. And so I think we kind of are in a position having tested this out that we believe we start to get diminishing returns potentially at let's say 13,000. We probably avoid any kind of diminishing returns all the way out to let's say 11,000 to 12,000. So when we start seeing diminishing returns I think is where we sort of call it a day and decide that's where we are going to call it. It's not a technical limit. It's just more of an economic limit.

Okay. Thanks. I'll leave it there.

Neal Dingmann, SunTrust.

Good morning guys. Thanks for getting me in. Scott, for you, or Tim, just wondering, when you look at Version 3.0 or 2.0, I guess I'm just looking at sort of Slides 9 and 10, and not only obviously are they well above that type curve that you had set out, but I guess what I'm getting at is kind of comparing that Version 3.0 and 2.0, it looks like initially they're relatively the same, and then you start to see some pretty nice expansion in 3.0 over 2.0 later on. Is that more just because the demand choke program you have initially and basically throughout you start to see a pretty good difference between the two versions?

You see -- let me just say the straight part of those curves is the period during which the wells were choked, which means we are limiting them on a daily basis. When you open the choke, you start see the thing bump up and go above the line, so that's precisely what you're looking at.

Got it. And then just lastly very quick, just on the production guidance that's given out there, with five rigs coming on and obviously this enhanced completion, how -- and I don't think you've given the exit rate but how do you think of -- I know you've got, Scott, the 2017 sort of guidance out there. You've obviously got the 2016. Should we think of it just being a bit pretty linear or because of the five rigs coming on, you'll have a bit of a bump the first half of next year?

Yes, I think we will continue to be -- we are in that 13,000 to 17,000, and we may see a quarter or two bump up, but it's going to be fairly close to that very consistency.

You do see waves come, depending on when you put rigs on. The wave comes six months after you put a rig on just because of the completion time, our drilling and completion time. So I think you'll see a wave as we get into the early part of 2017, a positive wave. And it just depends on if we had any further rigs in 2017 where you get other waves in the rest of next year.

Makes sense. Thanks guys.

Jeb Bachmann, Scotia Howard Weil.

Good morning guys. Just a couple of quick ones. First on I guess the Eagle Ford, any communications from Reliance on resuming activity with the uptick in the commodity and the improvement in your differentials down there?

So we are in the middle of discussions on that, so we are sort of precluded from giving you much detail as we are evaluating the 2017 capital budget. But suffice it to say Eagle Ford is sensitive to needless to say oil prices because we produce condensate there, so that has an effect, but also NGLs, particularly ethane. Of course that's improved some as well. Natural gas prices are important to us as well. We will be watching all of those with our partner and evaluating how many rigs to run, if any, for next year. Of course, I think we would prefer to run some rigs and I think our partner would too, but that's just simply a matter for the JV to come to conclusions on.

Okay, great. Tim, any update on storage for the Permian volumes down in Midland and maybe in Corpus Christi?

It's Rich. That tank is up and running, and so we've got 600,000 barrels of storage capacity down there and we're using it today and mostly selling in the domestic market today. And then in Corpus Christi, that one is still not supposed to be on until later this year.

Any idea on the size of that one?

It's Oxy's facility, so I don't have the -- I don't know the exact size off the top of my head. But it's big.

Great. I appreciate it guys.

That concludes today's question-and-answer session. Mr. Sheffield, at this time, I will turn the conference back over to you for any additional or closing remarks.

Again, thanks. I'll be seeing most of you all over the next few weeks as we get out these last energy conferences over the next few months. Looking forward to the last call for myself. I'm turning it over to Tim here in, what is it, in November?

The call is in November. The date is December 31.

Thank you all.

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