Pioneer Natural Resources Company (NYSE:PXD) Q2 2016 Earnings Conference Call July 28, 2016 10:00 AM ET
Frank Hopkins - Senior Vice President Investor Relations
Scott Sheffield - Chairman and Chief Executive Officer;
Timothy Dove - President and Chief Operating Officer
Richard Dealy - Executive Vice President and Chief Financial Officer
John Freeman - Raymond James & Associates, Inc.
Doug Leggate - BofA Merrill Lynch
Pearce Hammond - Simmons & Company International
Evan Calio - Morgan Stanley
Paul Sankey - Wolfe Research
Brian Singer - Goldman Sachs
Charles Meade - Johnson Rice & Company
Ryan Todd - Deutsche Bank
Neal Dingmann - SunTrust Robinson Humphrey
Jeb Bachmann - Scotia Howard Weil Incorporated
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 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 August 22, 2016.
The company's comments today will include forward-looking statements made pursuant of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. The statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results and future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's news release on page two of the slide presentation and in Pioneer's public filings made with the Securities and Exchange Commission.
At this time, for opening remarks I would like to turn the call over to Pioneer's Senior Vice President of Investor Relations, Frank Hopkins. Please go ahead, sir.
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 quarter for Pioneer, which saw the company continue to deliver solid execution and outstanding performance. Scott will then review our latest outlooks for Pioneer for 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 for 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 this Spraberry/Wolfcamp. Rich will then cover the second quarter financials and provide the earnings guidance for the third quarter and after that, we'll open up the call as always do for your questions.
So with that I'll turn the call over Scott.
Thank you, Frank. Good morning. This is the first call since my announcement to retire as CEO, I want to give you few comments before I go over the first two slides. I’m maybe setting a record but I am 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 here to be a leader wants to retire and pick the best time, I thought that 2014 was that time. But seeing what the company has done to this is downturn 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 is more important with Tim and the management team is been with me over 20 years. We got the best management team in a bit I'll make a few comments on the best long-term growth profile of any large GAAP company out there.
I have only got a couple of slides as I transition to Tim, so can we turn off with slide number three. With the quarter the company had adjusted loss of $37 million or $0.22 per diluted share, production way above guidance, 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 per day or 5% versus first quarter, oil production up 12,000 barrels per 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 to 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 cost coming down on per lateral foot, which Tim will talk about.
Again, a great achievement, we are continuing to see production cost per BOE by 26% from first half of 2015 to first half of 2016. You will see Rich talk more about it and also Tim, but what is an amazing to me is that the horizontal well operating cost excluding taxes is down to almost $2 per BOE. So definitely we can compete with anything that Saudi Arabia has.
A lot people are asking why with the deep inventory, why we 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. The most competition couldn’t bid on this, because it couldn’t give longer laterals.
We had it totally surrounded, allocated 14,000 per acre and what is the interesting right after we've made the announcement on the acquisition somebody is paying 58,000 per acre right next to this acreage. Closing expected in third quarter and you will see from the slides, this is the best area in our horizontal being Wolfcamp area, wells will be between $1.5 and $2 million BOEs.
Going to slide number four, the company plans to increase its source horizontal rig count as we announced already from 12 to 17 rigs in the Northern second half of 2016. First rig in September followed by two rigs in October and two more rigs in November. Three of those rigs would be dedicated to Sale Ranch area, once locations are permitted.
We already talked about the slight increase in capital expenditures about a $100 million to $2.1 billion, and again obviously is it takes us to 125 to 135 days to bring wells on. Production, we won’t see any production until 2017. But we’re increasing our 2016 production forecast from 6% to 12% to 13% plus. At the end, due to higher forecasted growth rates from the Spraberry/Wolfcamp well productivity.
The 2017 rig activity is expected to deliver production growth ranging from 13% to 17% in 2017. Again funded by our strong investment grade and really to bet balance sheet in the industry, a strong derivative position and forecasting cash flow assuming mid July strip prices.
Just last comment, before I turn it over to Tim, is probably what is most important in this whole slide deck. The Company expects deliver compounding your production growth of 15% and maintain debt to operating cash flow below one to 2020 and mid July strip prices. And what is most important that the strip price is at 2017 or 2020 has only dropped about $2 to $3. So what has happened obviously the front month has dropped about $10 from $51, $52 down to $42.
So obviously we could ask all 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 his way to grow on 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, could be in 2019 , we are using 2018 here. That’s also what is amazing for me. So I prefer long-term that the strips stays where it is. Somewhere in the $50 to $55 this pioneer and outperform every indefinite, especially the large cap.
I’m going to now turning it over to Tim to give you more detail on the CapEx.
Thanks Scott and I’m turning now to Slide five, 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 added here in the second half for the year.
Pad drilling as he mentioned, will have the effect of having, this is not impacting 2016 production but rather it will start to come into 2017 and when we add new production from these rigs. Essentially rather than going to the details in the slide, I would simply say all other capital item remain essentially 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 now.
Turning to Slide six, we’ve updated our production guidance going forward that 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 at all the quarter, as 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 total production right 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 is a lot of mechanical reasons for that, but some of them have to the fact were are 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.
And we have a larger number of offset wells in this particular upcoming quarter that it 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 over burden our facilities. All those were just coming in 2016s thirds quarter, 2016s fourth quarter looks extremely strong. So this gives simply a scheduling related matter that has this effect.
Finally, as a result of what Scott has 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 or 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 the operational standpoint and we plan to execute accordingly.
Turning out to Slide seven, the recently announced acquisition I feel like is very opportunistic and has the effect of further high grading our portfolio with some of the best acreage in the Midland Basin. 28,000 acres or so in the Midland Basin, our associates are spread from Sale Ranch all the way down into Northern Upton County, but the main focus and the main reason to do 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, I have got a graph to show you the results of those wells coming up. And what this transaction does is, it adds 70 long laterals in the Wolfcamp B at high working interest, each of those we feel like based on where the return metrics look today at $10 million with an NPV. So right there that translates into $700 million of value just in drilling those locations, which goes show you I feel like economics of this transaction are really outstanding.
It also adds other locations about 80 Wolfcamp B locations, but have lower laterals length and a lower working interest, we need to go to work on these areas by acquiring additional interest as well as potentially trading acreage to increase the length of those laterals, but we've 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 is signal so we might do more of this type of transactions. And 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 the acreage that I mentioned a minute ago in order to drill longer laterals. In fact, since early part of 2015 we've traded 19,000 gross acres and have a required $3.2 million growth lateral length in terms of feet for no cash exchanging hands. And 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 eight, this is the Sale Ranch data, I mentioned a minute go across all of our acreage of course continuing to build on our success when it comes to completion optimization, but first to the Sale Ranch this is the main focus of course of the Devon transaction. Overtime in this area of the field we have placed 41 Wolfcamp B wells on production that’s over the last two years, that’s wells that are over 7000 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 grey line R&D above the 1 million barrel type curve, but not significantly. It's when you start looking at the 23 wells performance in the blue or we start to see the benefits of optimization. Many of these wells that of the 23 were subject to version 2.0 completion. And you can see as a results, these wells on average are exceeding that million barrels type curve by about 60%.
And 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 of those wells currently on production, but nonetheless you are 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 year and we have drilled a lot of wells in the area and that’s why we think the Devon transaction accrete such great value to us. And as we learned and continue to refine this completion optimization in the area I think this Sale Ranch acre is expected to show very strong results going forward.
Turn on Slide nine, this is more granularity, especially on competition optimization. In the Wolfcamp B this is both in the North and the South. You will noticed that the graph shows some early results about three months of results are so on version 3.0. First in the North, at the top part of the slide you can see that we had about 14 wells that were subjected to version 3.0 style competitions.
The first 45 days are so of that data really needs to be tossed out as NA, 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 wait the ability to handle these significantly increase volume of water being pumped into these wells. But if you take a look at the version 2.0 results, they are outstanding course probably 35% improvement over the million barrel type curve.
But we are looking forward to see the fruition of all the version 3.0 wells. You can see we have had wells on improving on production. Only on production without being choked back for about a months. 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 tune 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 essential the same. We don’t see quite as much pick here in the version 2.0 case of about 25% in the South, just a product of less pressure as further you go to 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 were 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 will know a lot more over the next couple of quarters about what version 3.0 can attribute, on a per well basis, but sufficed to see these early results are positive.
Now turning to Slide 10, here we’re talking about completion optimization in the Wolfcamp A. The Wolfcamp A verses is a zone which have not drilled nearly the same number with a large sample size of wells compared to the B, but we’re showing similar style results. Wolfcamp A early day 2.0 wells now after having been on productions, in some cases almost as long as a year, they have showed about 25% productivity improvement.
While the 3.0 wells are in a similar position, as we seen in the Wolfcamp B that is early days, just completing their choke management period. In the Southern Wolfcamp areas there is only the one 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 began the see for revision 3.0, we’re evaluating whether to expand the current 80 well campaign to a larger of number wells as we add rigs here in the later part of the year into the next year. We will be getting back to you with more details on exactly how many wells we are expand that to as the team completes their work.
Turning to Slide 11, this is lowest grade rate shale data, just to update you on that. You can see that all 24 wells are show and drilled with 2.0 versions style completions. They still show about a 10% improvement over the one million BOE type curve. I think the take away from all of these slides are significant in the sense that we now have a 150 wells with version 2.0 data and we can pretty definitely say, that’s going to be the new style of completion 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 cease more time before we can really tell you definitively how good they are going be.
Choke management occurs, still impinges upon our ability to see early well production results. But I think is the case that not only will we put the 43 additional wells on, using 3.0, but we’ll look at actually increasing the size of that campaign as we get into the later part of this year and to next year.
Slide 12 turning to cost efficiency, Scott covered some of this but I'll try to be brief with it, but sufficed 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 cost are higher as a result for that. we have continued to more than offset that cost increase and continue to drive down overall D&C cost.
You see year here over the last year and half or so, the 35% decrease in our D&C cost, despite effect that we’re adding costs, and that’s not in significant cost when we’re doing version 2.0 and 3.0 completions. There are lot of reasons for that. You may recall last year, we ended the contract for both our tubular and cement pricing, substantial reduction this year, probably 30% to 35% reductions.
We also see continual completion efficiency gains, one way to do that is to reduce our non-productive time where we just simply reduced the number of days on the job and that reduces all of the cost that are driven by time, including things like rentals, supervision and labor.
So we are seeing a lot of improvements when it comes to that period of the business as well, but we have room for further improvement. Our rig rates today are still based on the old contract rates that will start peeling off as we get into the 2017 and 2018 where we can then expect to see spot rates for rigs, which we have been waiting for some time.
I'm going to turn now to Slide 13 to 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 fiver rigs coming up here in the next few months, we expect to place 230 wells on production. You can see the splits there, it’s 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 you will know a lot more about 3.0 as we go, but we reduced our D&C cost 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 in the last quarter we were talking about this ranging from $5 to $7 per BOE, which includes both LOE and taxes.
Now we see that its $4 to $6 per BOE and 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 cost. The results of which is very high IRRs, even though we are in this price deck that we face, in this case 50s low 50s and in past really in the low 3s.
But the fact we haven’t been able to reduce our cost and improve our efficiency to the point, but 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, it's my last slide. This is a slide show on how all this translates into production growth. We did have a tremendously good second quarter. This is just specifically Permian Bain 167,000 BOE per day that allows us to bump the whole year up to an average of 168 despite virtue of that early good performance did put 69 wells on production, but the vast majority on the Northern area we are completing on the Southern area wells.
We will have those mostly done in this quarter, and we did complete more wells ahead the plan and 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 shutting volumes from offset fracs 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 those lead to notion that the third quarter would be more flattish than we would have expected compare to the second quarter. But it has to do with all these reasons including the curtailment of the wells with choke management.
So overall, I would say this was a very strong quarter operationally and I think just as a thing as going forward as we shift to see outstanding results from these assets in the future. And with that, I'm going to pass it over too 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 $268 million or $1.63 per diluted share. That did include noncash mark-to-market derivative losses due to the higher commodity prices at the end of June versus at the end of the first quarter. So those losses after tax basis totaled $231 million or $1.41 per share.
So after adjusting for the mark-to-market losses we are at $37 million loss for the quarter or $0.22. If you look at the middle of the page where we show the results for the quarter versus or guidance, you are going to see that production as Tim and Scott mentioned was very positive. Our cost initiatives are bearing fruit and coming down. So we are on the positive side of the guidance and a number of these things are within the guidance. So really, an overall exceptional quarter financially, one of the point to mention is we have just under $410 million of operating cash flow for the quarter as well.
Turning to Slide 16, look at our price realizations on the bars there you can see that oil prices were up 47% to $41.43 for the quarter, albeit 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 expensed during the quarter. And 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 that third quarter will better than the first and second quarter.
If you look at our oil price differential for the quarter it was down $1.21 from where we were in the first quarter, that’s really from the two things. I think we mentioned these in on the first quarter call, was one, our Eagle Ford condensate contract, we had new contract. It 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 to 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 form derivatives and brings our total to $349 million through the first six months for the year.
Turning Slide 17, look at production cost. Once again, Tim talked about it, but the assets 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 cost per BOE are 9% from the first quarter, base LOE was down about 5%.
Centralizing our maintenance, the cost initiatives of the asset teams have going on, reducing our salt water disposal handling costs, labor cost were down as we are really covering the increased activity with the same headcount. We are using gas lift versus electricity or submersible pumps to support our wells and lower fuel and electric cost as well.
The other thing that you will notice here is when you look at our third-party transportation cost on a per BOE basis, those were down really due to our decline in Eagle Ford production, which is the bulk of our transportation cost. And so on our weighted average basis as the company continues to drilling and it becomes a smaller portion if it, you will 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 they are low operating cost $2 to $4 before taxes, and $4 to $6 in total on a more weighted average basis and our production cost will continue to benefit from those well as we add more of that production in the future.
Turning to Slide 18, it really sums up the last two slides from a margin standpoint. A new slide that we have added. It really highlights why we had 90% of our capital budget focused on the Spraberry/Wolfcamp, and why we are comfortable adding rigs going into the future and its really tremendous that its cash margin in the premier horizontals are more than twice any of other assets and the low operating cost 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, excellent position, probably we are the best in the industry today with the net debt at the end of quarter of $300 million and undrawn credit facility of $1.5 billion. At the end of the quarter, we had net debt to forecasted cash flow and 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.
You look at the timeline in the middle there, you will see the 2016 debt maturity that it was actually due in mid July, so that was paid with cash on hand. We also have their maturity that’s due in March of 2017 and then also was free funded with the bond offering we did last December and we paid-off it with cash on hand as well.
Turning to Slide 20 and really focused on third quarter guidance, daily production 232,000 to 237,000 BOE, 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 offset wells, they will be shut in as we frac those wells during the quarter.
Production cost of $8.25 to $10.25 per BOE really reflects the lower run rate and the effort to the asset teams to continue bring those cost down. The rest of the guidance is consistent with second quarter results and prior quarter guidance. So 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.
Thank you [Operator Instructions] We'll take our first question from John Freeman with Raymond James.
On the big cost reductions that you all had during the quarter despite the bigger completion jobs that you are 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?
Well, of course we are seeing John, some of the cumulative effect of things we have done in the past as well. In other words, we’re just now to the point where we would say we’re full run rate at lower tubular cost, as well as cement cost I mentioned, of course it took us a while to burn off inventory from what we had at the end of the last year.
So now we are at a run rate, which just reflective of spot pricing, which is very low compared to last year, but there is really a lot more of the same as what already captured it. I know that we very substantially reduced our non-productive time completions, which as I mentioned, I think our non-productive 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 wire line as an example, reducing mechanical failures where we can, and when you start reducing non productive time, that substantially has a very positive effect on things that we get charged on a daily rental basis.
And for that matter its supervision, the job is on, 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, they just have the effective 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 have 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?
Hey John, 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 yet. 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 cost will be that our cost 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.
Okay, that helps. Thanks again guys. Well done.
Okay, we got a next question from Doug Leggate with Bank of America.
Hi 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 are 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??
Yes, Dough I mean I think what is amazing to me that we can achieve 15% production growth up to 2020 in 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 got to factor in though is what is going to happen in the service cost and we saw what happened in 2014. So, that's why I said that personally looking at the models with rather oil stay in the $50 to $55 range and keep cost in check, but as a large shareholder and so - but obviously as a curtailment the group have the lot of access 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?
So, Dough the way I would cash it would be in a $10 higher oil price 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 of let's say 2018 to 2020. So I would say we want to put 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 a lower prices. Right now, we have baked in adding three to five rigs per year in 2017, 2018, 2019 probably in that range and when we do that we have some dramatic growth increases that we have already shown you.
I think if you look then at what would you do to the extent you are higher than that we can actually put more rigs to work out with three or four year that’s clear. There is 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, I think it's just a matter of deciding how much to this PV that we want to bring forward. We certainly do 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 internal modeling $250 million, $300 million a year, of other PPNA 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, 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, which come from a more accelerated campaign.
And the water system of course is pretty clear that we are building out a substantial water system for higher a 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-off really well in the long-term. So there is more of the above we would need in terms of infrastructure, of course in a higher cash flow model we need to be prepared to fun all that.
Alright, I have taken up enough time. I'll let someone else jump on. Thanks.
We will take our next question from Pierce Hammond with Simmon.
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 Pierce. If you look at the immediate advantage we have is when things improved, today we only have five or even fleets working essentially full-time. When things improve and/or maybe you get back to Doug’s case where you have $10 higher oil before adding rigs, we have got two fleets already to go, at a 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 substantial. 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 would say the same thing about our sand business. We have ready sand available especially until 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 and not. That said, we are not making any money at vertical integration now that’s clear. That’s true to all our service companies. But we will also be protecting ourselves in terms of rate increase 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.
Its mainly the biggest component I mentioned is the gathering and transportation down there. So that’s basically as you know around $6 a barrel for condensate and mid $0.60 for gas.
Great. Thanks so much.
We’ll take our next question from Evan Calio with Morgan Stanley.
Hi, 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 I mean that’s defiantly the case and that’s the main point we’re trying to make that’s we can live within cash flow, keep a great balance sheet, company 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 have already said, the last the several years, on the company with 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 redeploying 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 said before Evan, it’s going to be - we are going to drill based on returns and so it will depend where commodity prices are, we are going to always give returns, but based on where the strip is, we’re very comfortable with the program that we in place.
So that could increase is I guess what I'm trying to understand.
Well I think as Tim said, yes, we saw $10 increase in commodity prices and yes we could increase to use that cash flow for high return projects.
Great. That makes sense. Thanks guys.
We’ll take our next question from Paul Sankey with Wolf 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 have talked about I think as much as a $100 billion need to develop your own acreage. I think the time frame was 2025. You have 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 don’t know when it’s going on the website, next week in next slide deck, but I’m speaking to 3000 engineers and geologists in San Antonio taking about the premium and so there is a interesting slide deck that will come out next week in their presentation. But I'm not firm belief as the Permian is going to be the only driver of long-term oil growth in this country. And it’s going to grow on, that’s about 5 million barrels a day from 2 million.
Even in this current strip, $55 price environment. So it’s got the best rock, obviously the best margins and it will provide essentially the only growth long-term. I mean the stack play and the scoot play, may be Niobrara do a little bit, but the Bakken and Eagle Ford I think there is no way they can recover to the level that have already had. so that's why I'm confident that world needs the Permian, the Permian is going to be the future of the U.S. and help in world supply.
That number that you have 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 down, just taken the well cost $7 million times 20,000 locations that’s the $140 billion. It’s an easy number to get to.
This is Frank. The good news is it's actually coming down from where it was before.
Well 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 Paul the current rates that we understand are being marketed up on roughly a $14,000 today 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 the higher price than we're dealing with today. In terms of commodities were struck at roughly 25 to 26, so I think there is a dramatic improvement in the waiting for us. I think the fact is, a lot of those rigs don’t come off till as we get into the later 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 the spot prices.
We’ll take our next question from Brian Singer with 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, but can you give us an update on water infrastructure plans, 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?
Well you have got two to three questions built in there. I would say that we have a big multiplicative effect going on right now, because in combination with one in the front more volume of water per foot, were also increasing average lateral lengths. So the amount of water we're pumping has gone up dramatically, it's easy to calculate some of these wells that would have gone up roughly a third compared to where it was done in the past, and we're already pumping quite a bit of water.
So, I think the answer is water is going to be a key, I think we had identified even a couple of years ago if 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 racking for that as we move forward especially in the scenarios of higher prices.
But sufficed to say we are taking water from these city of Odessa, this is effluent water as we speak, and we still plan on an agreement with the city of Midland to do the same, then contract with the city of Midland has us investing capital in their water infrastructure. We are spending many this year on some of our main line systems, but what we would want to do further work on our main lines and some of our secondary storage systems basically frac ponds as we move forward.
I think we can do it in a relatively piece meal basis, but as I said, as we're pumping higher volumes it becomes more problematic, in terms of volume needs. One thing we are doing is trying to get of course to where we are not using any fresh water. 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 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 one hand, but also this is brackish water sources. On the saltwater disposal front, you can kind of the other side of the coin, which is to say this water is when you start turning the wells on for production. Coming back to you, we are pushing more water down in the system of another completion of how that water comes back and you got a have a place to put it.
Rather than overbuilding the facilities at least, this is tank batteries for saltwater production, which had been generally speaking designed for lower volume. Now we have dramatically higher volumes of water just produced water coming back at us. Rather than overbuilding the infrastructure and in doing so basically creating a situation where you never would be able to use a peak capacity, we 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 you know in some cases you saw in the data that I showed you 45 days or 60 days and when the water starts coming off a system, then you would get to a point finally where the facilities can handle it. So I think we would rather [indiscernible] 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 the only that we would look at to wow this is going to blow the doors of the balance sheet from the standpoint, cost requirements from infrastructure. We use an example our Midland contract probably will roughly require $100 million of investment and we are spending $50 million to $100 million probably every year any way on the water systems. So 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 will see us still go about it in somewhat of a piecemeal fashion considering we are not at the point where we were in 2014. 2014 we were forecasting going from 25 rigs to 100 rigs over eight year period. I would say, today we are at 12 going to 17 and hoping to go to 30 over the next three year or so.
So we are really not in the same scenario we were in, but nevertheless we are pumping more volumes and so there is that affect. But it will be something we have to continually spend money on, but I think we will still do it more piecemeal, you are not going to see us coming out with a huge multi $100 million water project any given year.
And Brian that’s built in our five-year plan too, so if we factored that in and we are talking about this 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?
Well hey Brian I'll answer that, this is Frank. I got this question last night from one of your analyst brother and 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. I mean we are basing our forward program on that. So however, you want to couch it in terms of taking the type curve up, I think we signaled pretty loud and clear that we comfortable with the performance we have been seeing and we expect to see in the future.
I would add by just simply saying we are now saying that 2.0 is the standard.
Thanks very much.
We’ll take our next question from Charles Mead with Johnson Rice.
Good morning Scott, Tim, and to the rest of your team there. If I could, I would 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?
Well I think Charles, sufficed to say we were looking at 60 to 65 case to be able to achieve the same type of scenario, we’re looking at here, if you look at a year ago or so. And all we’re really saying is our model now has changed dramatically. So in this sense regardless of the commodity prices, our cost levels have come down, our productivity has come up to the point where, the old 60, 65 is basically now at 50 to 55, that’s what we’re saying. And this is from data, this isn’t just from smoke okay. This is from the well result we see and the cost we had been able to achieve and so that’s how its answers 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 mean, I'll leave that answer, I guess the question is going forward. We can actually grow it almost any rate we wanted, we have spend so 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 have changed this completion style, as you have gone to not just longer laterals but more water per foot, that sort of thing, have you had to - I think you have already answered this, that you have decided you are 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 are going to have to wait longer to learn what you would've learned earlier with…
Yes I think on trade, I think I mentioned that Charles, there is trade off , it has to do with not over building, when you only - we see this all the time in guess prices to give you an example, where you build a gas plant. And if you are not careful, you would build it for the capacity that exist one day and you see production declines and you only to use the capacity you built out and the extra cost for the minimal amount of times.
So there is this tradeoff between over capitalizing a project and/or the need for current production. I think we are in the range of 30 to 40 or 45 days in terms of choking the wells back. That’s really in material, I mean it does postpone our knowledge base for whatever that is 30 days, but we really six months or so anyway of production day to figure out and how these wells are going to do. We are not there to worried about the postponement of thirty days of knowledge that’s doable, and that’s reasonable cost to the trade.
Thanks Tim. That's good detail.
We’ll take our next question from Ryan Todd with 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 as appose to just 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 catch there 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 and then come back on delayed A's in the Wolfcamp. So that's just dramatic approach we are taking, that means we also need to come back later on for example lower strip ratio's zones and so on, but in terms of - as you look at the capital requirements of all that, what we do know is we need to build tank barriers here 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 wells would be subject to several million dollars worth of the capital just to put the facilities out there, the last wells are subject to 150,000of capital, because the fact the facility is 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 as we don’t want to overbuild for the future.
Alright, 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 have gone as long as 12,000 feet. Is it the longer, the better? Is there a trade-off at some point that you have 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 to 10,000 foot laterals today. We're building that inventory up as I mentioned vis-à-vis trades and another methods to make sure we could 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 is now being edging up to about 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 is probably a limit which we would call it today horizontal link, probably in the neighborhood of 13,000 feet maybe a little bit more than that just based on for the massive hydraulics. It's you have a lot of line losses that you pump volumes down that long as a horizontal pipe and so the risk you have is not getting of proper fracs especially at the toe of the wells.
And so I think we kind of are in a position of 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 turns all the way up to let's say 11 to 12. So when we start seeing diminishing returns, I think it's where we sort of call it a day, I think that's why we're going to call that. It's not a technical limit it is more of a economic limit.
Okay. Thanks. I'll leave it there.
We’ll take our next question from Neal Dingmann with 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?
Yes let me just say the straight part of those curves is the period during which the wells are choked, which means we are limiting on a daily basis. When you open the choke, you start to see thing bump up and go above the line. So that’s precisely what you are 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 have given the exit rate but how do you think of - I know you have got, Scott, the 2017 sort of guidance out there. You have obviously got the 2016. Should we think of it just being a bit pretty linear or because of the five rigs coming on, you will have a bit of a bump the first half of next year?
Yes, I think you know we are in at 13 to 17 and we may see a quarter or two bump up, but it’s going to be fairly close to that very consistency.
It’s just going to be waves kind of depending upon 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 will see a wave , this will get you get in the part of 2017 a positive wave. And it just depends on we add any further rigs in 2017 where you get other waves in the rest of next year.
Analyst : Makes sense. Thanks guys.
And we will take our next question from Jeb Bachmann with 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 Jeb we are in the middle of discussion on that, so we are sort of precluded from giving you much detail as we are evaluating 2017 capital budget. But sufficed 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 peers 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 matter for JV to come to conclusion on.
Okay, great. Tim, any update on storage for the Permian volumes down in Midland and maybe in Corpus Christi?
Its Rich. Well in Mainland the tank is up and running and so we have got 600,000 barrels of storage capacity down there and we’re using it today and mostly selling in domestic market today, and then in Corpus Christi that one is still not suppose to be until later this year?
Any idea on the size of that one?
Its Oxy’s facilities so I don’t know the exact size of the top of my head, but its big.
Great. I appreciate it guys.
And that concludes today's question and answer session. Mr. Sheffield, at this time I will turn the conference back to u for any additional or closing remarks.
Again thanks. I will be seeing most of you over the next two 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 November?
The calls in November.
Dates December 31st.
Yes, yes. So thank you all.
And this concludes today's conference. Thank you for your participation. You may now disconnect.
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