先鋒自然資源 (PXD) 2016 Q3 法說會逐字稿

Welcome to Pioneer Natural Resources third-quarter conference call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; Joey Hall, Executive Vice President Permian Operations; Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Senior Vice President of Investor Relations.

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be found accessed over the Internet at www.pxp.com. (Operator Instructions)

This call is being recorded. A replay of the call will be archived on the Internet site through November 27, 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 of Investor Relations, Frank Hopkins. Please go ahead, sir.

Thanks, Anna, and 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's going to provide the financial and operating highlights for the third quarter of 2016. It was another great quarter for Pioneer which saw the Company continue to deliver solid execution and outstanding performance. After Scott concludes his remarks, Tim will review our latest outlook for Pioneer through the end of this decade and discuss our 2016 capital program and the production forecast through 2020. Joey will then review our continuing strong horizontal well results and capital efficiency improvements in the Spraberry/Wolfcamp, as well as the drilling plans for this asset through the remainder of the year. Rich will then cover the third-quarter financials and provide earnings guidance for the fourth quarter. And, of course as always after that, we will open up the call for your questions.

With that, I'm going to turn the call over to Scott, but not without highlighting that this will be Scott's last earnings call as CEO of Pioneer after leading the company for more than 30 years. I know that I speak for Pioneer's management committee and all of our employees in wishing Scott and his wife, Kim, a very happy and healthy retirement.

We'll miss you, Scott. So, over to you.

Thank you, Frank.

Good morning. As Frank said, as most of you all know, this is my last earnings call after 25 years of being public. I want to extend a special thanks to all shareholders and to all analysts on the call on our great relationship that we've had over the years.

I'd like to give a brief message before I review the first two financial and operating highlights slides.

As a continuing, large, long-term shareholder and board member, I have 100% confidence in Tim and the management team that we will continue to make this Company the premier shale company in the world. We have the best rocks and balance sheet and the best employees in the industry. What company can easily grow 15% per year for 10 years and move up to over 1 million barrels of oil equivalent per day in a $47 to $57 oil-price environment?

If you look at the Permian only, that growth rate is well over 20% over those 10 years. What company has over 10 billion barrels of oil equivalent with over 20,000 locations at an average net revenue interest of 85% and essentially has zero basis on those locations, except for the recent Devon transaction? In an environment where companies are paying $40,000 to $60,000 per acre?

In addition, we are growing our oil mix from 57% this year to 62% next year and over 70% over the next 10 years.

With regard to oil prices, we are obviously not out of the woods yet. I give OPEC a 40% chance of reaching agreement on November 30th. And if they do, everyone will cheat. I have seen this over my 42-year career. The market will not balance until 2018. That is why Pioneer is best-positioned among all companies with great hedges in place for 2017 and the best balance sheet in the industry.

Now, we'll go to slide number 3 and financial and operating highlights.

We had adjusted income for the quarter of $22 million or $0.13 per diluted share. Third-quarter production, 239,000 barrels of oil equivalent per day, 56% oil. Above Pioneer's guidance range of 232,000 to 237,000. An increase of 6000 barrels a day or 3% versus second quarter. Obviously, driven by the Spraberry/Wolfcamp horizontal program and our completion optimization program.

We did have unplanned downtime at Fain gas plant which affected the quarter by 2000 barrels a day from West Panhandle production.

We did place 46 horizontal wells in production at the Spraberry/Wolfcamp in the third quarter with strong performance including 28 wells from 3.0 Version. Again, the 3.0 Version significantly outperforming 2.0. We did expand our 3.0 from 80 wells to 100 wells.

Continuing to realize significant capital efficiency gains in the Spraberry/Wolfcamp: again, through completion optimization, longer lateral lengths, enhancing well productivity.

Drilling and completion efficiencies and cost reduction initiatives are continuing to drive down cost per lateral foot.

On slide number 4, reduced production costs for BOE by 6% since the second quarter of 2016 and 32% since the third quarter of 2015. And yes, as some people may question, our horizontal Permian operating costs are $2.00 excluding taxes.

Enhanced Martin County acreage position by closing purchase of 28,000 net acres from Devon for $429 million. With the export ban removed last year, we did sell our first two Permian oil cargoes for export to Europe in the third quarter. We repaid mid-July debt maturity of $455 million with cash on hand, and with the recent run-up, of course, obviously three or four weeks ago, with oil prices, we did increase our 17 derivative coverage to 75% for oil and 55% for gas, up from 50% from last quarter.

I'll now turn it over to our next CEO, Tim Dove.

Thanks, Scott. I share Frank's good wishes for you going forward.

As we've been discussing for some time, we are in the midst of increasing our horizontal rig count, and we have a couple more rigs that did come in November to complete the total addition of five rigs. That will put us with 17 rigs in the northern Spraberry/Wolfcamp area by year-end.

Our capital program remains essentially unchanged. It's been that way for some time. That's since the Devon transaction was announced at $2.1 billion.

The truth of the rigs that I mentioned a moment ago will not really have any significant production adds until 2017. However, just the fact that we are improving our productivity in the Spraberry/Wolfcamp field area with a horizontal drilling campaign and completions optimization is allowing us to actually increase our forecast for this year's production from 13% plus to 14% plus.

We see now, even with the 17 rig count being maintained flat, we would expect to deliver production growth ranging from 13% to 17% next year. Really what we are finding, of course, is we can continue to do more with less as we continue to optimize our program.

The 2017 campaign of drilling is well-funded already with our balance sheet on the one hand and also, as Scott had mentioned, our strong derivatives position having been built up considerably over the last few weeks and our cash flow assumptions based on upstream prices.

The current 2017 capital budget is far from finalized. There's a lot of discussions, of course, that are ongoing with our partners and internally as to where we're going to land the budget, but suffice it to say we are currently looking at numbers that are in the range of $2.7 billion to $2.8 billion for 2017.

One of our more critical messages in this whole presentation is in the yellow box at the bottom of slide 5, and it's the fact that, as Scott had mentioned, we were on a plan here to increase our annual production growth rate to about 15% for several years and in doing so keeping exceptionally strong balance sheet, in this case net debt to operating cash flow below 1.0x, even using only strip prices. And in addition to which, if we grew production at that 15% rate, our actual compounded annual growth rate of cash flow exceeds that and is approximately 25%. That has to do with drilling projects that are high margin oil-based in terms of their returns.

And one of the major components of this is -- and our internal modeling certainly supports the fact that we can do this while spending within cash flows as early as 2018 -- and that's assuming about a $55 per barrel oil price case.

So this is what we're focused on really for the next several years, one of the main components of which is a minimum cash flow neutrality, which, as I said, I think we can reach 2018.

Turning now to slide 6, I mentioned a moment ago our capital budget remains essentially unchanged 2016 at $2.1 billion. The splits as shown on this slide are also essentially the same. Our cash flow number appears to be coming in as we had projected, maybe $1.5 billion. With cash on hand we easily can fund this $2.1 billion this year. And as we look forward, we would say the same thing about 2017.

Turning then to slide 7, and this is our production-growth forecast and history, you can see that essentially we are right on schedule when it comes to our production growth. The new forecast for 2016 being moved up to 14% from 13%, as I had mentioned, that gives us approximately the new number of 233,000-plus BOE per day.

If you look at the quarters, quarter three was, I guess, substantially above our range. The fourth-quarter production range we show here is a bit of an estimate, only because as has been evidenced by some of our earlier commentary and the material Frank put out last night, we have had an upset at our Fain gas plant in the West Panhandle field area. That is in the process of being rectified, but it's unclear how many more days we think that's going to take before we can get to full production. So what you see here is us being relatively conservative to make sure that we can get that plant back and in full operation.

But, as you look forward and if you look towards the future growth, we are reflecting on this slide the 15% CAGR growth rate through the end of the decade. If you do the math on this, this gets us to over 400,000 barrels a day by 2020. And oil growth is, of course, a considerable component of that.

There's been some discussions and questions that are raised by where we came out in terms of our oil content. The production for the third quarter showing at 56% where we had 58% in the second quarter. This is relatively easily explained by the fact that we've put in our target a gas plant in the Martin County area -- this is referred to as the Buffalo Plant in April of this year -- and, of course, in doing so, we had to assess and project what sort of NGL recoveries we could get from that plant.

It turns out they are substantially better than what we thought, and so we have to go back in that sense in the third quarter and do an accrual adjustment for those additional NGLs. So that's a very big positive at our NGL fraction. That plant is significantly higher than what we had thought.

In addition, if you then match that up with the fact that we had really substantially higher offset frac shut-in wells, we had about 5000 barrels a day shut in. If you average for the second quarter, that increased to 10,000 barrels a day in the third quarter.

We're obviously very busy out in the field. We've got more rigs running. We have our own frac fleets running. We don't adjust down in terms of the quarter, and those frac fleets, they continue to work, and our shut-in production numbers move up and down every week. But suffice it to say, on average much higher shut-in production in the second quarter, and that's a good thing because that means we're actively working on new wells.

The final thing I'd say in that regard is that our new wells do continue to show initial production percentages of about 80% for oil. And that's a good thing. The [GORs] do increase slightly due through the course of the life of the wells, but suffice it to say, we're still seeing IPs in the 80% oil. So that is all going exceedingly well. And I would also follow on by saying there's some discussions surrounding our oil growth, and it was substantially higher in the second quarter than the third, and that has to do with a couple of factors.

One is our top numbers were substantially higher in the second quarter. About 69 wells were put on production. Where in the third quarter, as scheduled we only have a lesser number. In this case, we popped 46 wells. But by definition, your oil growth rate would be a little bit less in that scenario.

And then in addition to which, the same effect occurs vis-a-vis the shutting-in of offset frac wells that has about a 5000 barrel a day increase in the wells that are shut in in the third quarter compared to the second quarter.

But all-in-all, I guess the message is that we are right on schedule on this forecast, and I think it bodes well for our ability to keep running the factory and to keep moving forward with even a higher level of activity.

With that, I want to turn the call over to Joey Hall, who is our EVP of Permian Operations.

Thanks, Tim. I am going to be picking up on slide number 8.

Here you can see the impressive performance from our Version 2.0 completions continues. We're still trending 35% above the 1 million barrel-a-day equivalent type curve in the North and 25% in the Southern JV area with four more wells added in the North and one in the South.

We also continue to see a positive balance for our Version 3.0 completions when compared to 2.0 in the North with three additional months of production data and 15 more wells.

The same story with Version 3.0 completions in the south with five additional wells added in Q3. And, as we mentioned last quarter, the early results of the new pops were masked somewhat due to choking, but we are now starting to see some good separation for our 3.0 completions.

Moving to slide number 9, similar to the previous slide, we continue to see the improved performance from our Wolfcamp A wells in both the North and South. In the North, Wolfcamp A Version 2.0 is still showing a 25% productivity improvement with two additional wells added to the mix. Wolfcamp A Version 3.0 wells in the North are also showing a performance improvement over 2.0 with three more months of production data and eight new wells.

There were no new 2.0 or 3.0 wells added in the Southern JV area in Q3, and of course, the same caveats apply on early choking of the new wells.

Moving to slide 10, same story on lower Spraberry shale wells for our Version 2.0 completions, which are still tracking 10% above the 1 million a day type curve with 10 new wells added.

Just reiterating the messages from our recent well performance, 2.0 completions continue their strong performance in all intervals with no retraction on our performance that's been stated in the past. And early favorable returns on our 3.0 completions has led us to expand our optimization program from 80 to 100 wells. And we will continue to use choke management going forward to optimize the utilization of our water disposal infrastructure. So some of the early results may be somewhat held back, but long-term performance is looking very good.

Moving to slide 11, D&C costs have continued their downward trend, even though our completion sizes have increased materially with Version 2.0 and 3.0 completions, which can add between $500,000 to $1.5 million to the cost of a well.

For perspective, I recently compared this quarter to Q3 of 2015, and we are replacing on average 25% more sand and 50% more water per well and drilling longer laterals for $145 less per foot than we were Q3 of last year.

I'd also like to emphasize the range of well costs in the upper-right corner, which shows lower Spraberry wells averaging $670 per foot and also highlight that we delivered Wolfcamp A wells for an average of $5.8 million.

The bigger graph, of course, only reflects Wolfcamp B wells, which also includes a growing population of what we refer to as lower Wolfcamp B wells, which are typically slower drilling than the upper B targets.

Bottom line: when coupled with the improved well performance, our capital efficiency continues to improve.

Moving to slide 12, this is a new slide, so I'll spend a little time explaining it. The data comes from IHS, and it captures new wells with at least three months of production data between September of 2015 and June of 2016.

It's important to point out that the data is not normalized for lateral length, which will be an important point here in a moment, and the Y axis illustrates the number of new wells with at least three months of production with a first production date after September of 2016.

The X axis is the average cumulative oil produced per well over a three-month period. So whenever you look at this, some key takeaways: no surprise -- the scale of activity is significantly above that of our peers in the Midland Basin with Pioneer putting on nearly twice as many wells as our nearest competitor. So the next question is, at this high activity level, is there any dilution of inventory? However, in this case you can see, Pioneer is consistently delivering strong wells which highlights the quality of our acreage position.

The fact that the data is not normalized further highlights that lateral length is important because it illustrates the contiguous nature of our acreage and our ability to consistently drill longer laterals.

And then lastly, it demonstrates that our completion optimization efforts continue to be successful.

Moving to slide 13, just a few highlights here, some of which have already been covered. We are in the process of increasing to 15 rigs near-term and will be at 17 rigs by year-end.

We remain on target to put 230 horizontal wells online with a mix of wells shown there.

Version 2.0 completions remain the standard with another 20 wells moved to Version 3.0 from the original 80, and we are now forecasting 50% to 65% IRRs with Version 2.0 and 3.0 completions and late October strip pricing.

Moving to slide 14 and my last slide, production growth remains strong with production up to 179,000 barrels of oil equivalent per day in Q3. We are planning to put 60 new wells online in Q4, which will be weighted mostly late in the quarter, with production between 185,000 to 190,000 barrels of oil equivalent per day. This raises our year-end outlook in the Permian to 170,000-plus barrels of oil equivalent per day and 36% production and 38% oil growth over 2015.

With that, I'll turn it over to Rich for the financial highlights.

Thanks, Joey. I'm going to start on slide 15, and we reported net income attributable to common stockholders of $22 million or $0.13 per diluted share. It did include non-cash mark-to-market derivative losses of $59 million after-tax or $0.35 per share. This is due to prices at the end of September being higher than those at the end of June 30 for those derivatives that are yet to price in the future.

Also included in the quarter was an unusual item related to a deferred tax benefit that we are recognizing a tax credit on R&D work for horizontal drilling wells, innovations that we've had from 2012 to 2015. So, that was also $59 million going the other way or $0.35. So, adjusted for mark-to-market derivatives, unusual items, we were still at $22 million of income or $0.13.

Looking at the middle of the page, where you can see how we came in relative to guidance, you can see it by looking down that list that we came in better than expected and were within guidance on all the items listed there. So another really strong quarter for the Company.

Turning to slide 16, look at price realizations. If you look at the bar charts there, you can see that oil was quarter on quarter was flat with our realized prices being at around $41.40 a barrel. If you look at NGLs, we were down 12%. That's mainly due to lower propane and ethane prices during the quarter. And then gas, if you look at the red bars there, it was up 46%, just due to the supply and demand fundamental changes that we've seen over the last few months.

If you look at the bottom part of the slide, on derivatives you can see the Company continues to benefit from our strong derivative position. During the quarter, we recognized $184 million of incremental cash flow. That brings us to $533 million for the year through nine months.

Turning to slide 17, looking at production costs, you can see here by looking at the chart that we continue to trend lower. We're down 6%, as Scott mentioned, quarter on quarter, and it's mainly driven by our cost-reduction initiatives and mainly on costs on repair costs, maintenance costs, chemical costs. Those are all down significantly over the time period shown here.

So, overall, production costs continue to trend lower. They are benefiting from the new Spraberry/Wolfcamp wells that we're drilling that Scott talked about at $2.00 operating cost before taxes and $4.00 all in.

Turning to slide 18, this is the second quarter we've shown our cash margins by asset, and once again, it just highlights the cash margins that are being generated in our Permian horizontal wells, just under $30 for this quarter, 70% on oil for the reasons that Tim talked about. So, really just highlights why we continue to invest over 90% of our capital budget into the Permian drilling and just given the high rate of return these projects generated at 50% to 65%.

Turning to slide 19, our liquidity position. Excellent liquidity position with net debt at the end of the quarter of $300 million, undrawn credit facility of $1.5 billion, so terrific financial position.

If you look at the maturity chart there, it is worth noting that the March 2017 bond maturity has already been pre-funded. We plan to pay that with cash on hand in March of next year.

Turning to slide 20, looking at our fourth-quarter outlook, production guidance is 237,000 to 242,000 BOEs a day, really reflecting the down time at West Panhandle. So that's 2000 to 5000 barrels a day lower than what we probably normally would have been, and that obviously reflects the -- our legacy assets that we are not investing capital in today and their decline.

The other item that is a change is production costs. You can see that $7.75 per BOE to $9.75 per BOE, really reflecting our lower run rate. And the rest of the items here are all consistent with our third-quarter results and prior-quarter guidance. I'm not going to go through those individually, but they are there for your review and modeling purposes.

So with that, Anna, I think we will open up the call for questions.

(Operator Instructions) Doug Leggate, Bank of America.

Scott, first of all, congratulations again. It's been a lot of fun, and I'm sure you'll be listening in as you go forward.

Thank you, Doug. Thank you.

Tim, the detail on the oil cut I think is getting a lot of attention this morning, so I appreciate you digging into that. But I wanted to ask you about the trajectory, and I'm looking at, I think it's the slide number 7.

So, if I look at our oil cut suggested for 2017 -- 2016, sorry, the 57% oil for the year, if my math is right, I would suggest Q4 needs to be up by around north of 58%. Does that sound about right? And if so, what's changing back again to give us confidence that you're heading towards north of 60% in 2017?

I think 58% does sound right is the answer to the question for the fourth quarter, approximately. And the reason I think that that's really doable, is because the whole reason we hit a lower percentage into Q3 was related to NGL accrual adjustment. So that is a one-time adjustment and won't recur. We are back to our trajectory.

And going into 2017, now you are still comfortable with the north of 60% number, or are we going to get more of these kind of changes or adjustments?

I think that the number we show is what we believe from our modeling, 62%-plus, potentially.

All right. I appreciate that.

I guess my other question is really more on the 15% target. I mean, it seems pretty clear to us, anyway, that your Version 3.0 wells are coming in substantially above the Version 2.0, which is what your guidance is based on. So, I guess, so there's a Part A and Part B. Part A would be, what do you need to see to reset that type curve because you development planned? And secondly, would you manage towards the 15% sort of go-forward target, or would you do more with less, or would you expect to maintain the same level of activity and, therefore, lead the risks to the upside and the target? How do you think about planning?

Hey, Doug. This is Frank. I'm going to try to address that for you.

If you look back at Version 2.0, I think it's fair to say we probably wanted to have and had six to nine months of data before we really got comfortable that we wanted to base our projections on that. And, you know, now we have. And, in addition, now we're looking at 3.0, but we've only got three to six months, six months on our longest wells. And if you think about it, some of those wells -- several of those wells have been choked constrained. So, we don't have a lot of data.

So I'd guess we're going to want at least nine months of data before we declare victory and really go all-out to do our forecasting on that basis. But, as Joey said, our confidence level is pretty high. I mean, we've increased from 80 wells to 100 wells this year, and we are looking pretty strongly at a program next year that will certainly have a majority -- maybe all of our wells will be 3.0 or most of them will be.

So, again, it's a matter of getting enough data because we want to have confidence in what we are forecasting, so we're giving out good numbers and realistic numbers we can achieve.

I appreciate the answer, guys. Thank you.

John Freeman, Raymond James.

Just echoing everybody else, Scott, congratulations and all the best in retirement.

When I look at the incremental 20 wells and the expansion of the 3.0 plan, should I assume that the mix stays relatively the same between the North, the South, the A to B, or is there any -- those 20 incremental wells going anywhere in particular?

No, it's pretty much spread out across the field, John. So you should look at it from that perspective.

Okay. And then my one follow-up, just again longer-term, I mean obviously huge gains on the productivity side the last few years, huge gains on the cost side. Should I assume that on a longer-term basis that maybe sort of determining the optimal kind of well spacing becomes one of the top priorities going forward?

Yes, John, well spacing is certainly at the top of our list, and that is one of the biggest knobs that we can turn to impact productivity. Of course, every time we change our completion design, it may require us to tweak that a bit. But I feel like that with the number of wells we have on the ground, we're really starting to zero in on the appropriate spacing, and that's certainly a key driver.

Great. Thanks, guys.

Charles Meade, Johnson Rice.

Tim, if I could ask about this -- the shut-ins for offset fracs, and that's something that we've heard about I think from you guys but also from other industry players, and I'm curious about how we should expect that trend to look going forward.

As I imagine, as you increasingly fill in your footprint with horizontals, the amount of volumes you have shut in in any quarter for offset fracs will probably go up. But, at the same time, probably the variance from quarter to quarter will go down. Is that the right way to be thinking about it, and can you give us how you think about it and how you will forecast it going forward?

Sure, Charles. I think you're right on. I mean, to the extent we have more rigs running more wells, getting completed, this type of shut-in data in the background becomes less and less discernible. It's to right now we're in a situation within the third quarter, as I mentioned, we had 10,000 barrels a day shut in; that is highly visible when you do the numbers.

I expect, though, with our activity levels increasing -- for example, in the fourth quarter, we're also estimating about 10,000 barrels a day shut in. That's in our forecast. But, as you go forward, I think there will be a percentage of shut-in wells that correspond to the activity level.

And the other way to look at it is, as you know, because we talked about this from time to time, part of this year's campaign and certainly part of next year's drilling campaign and completion campaign will have us coming back to areas where we've already drilled and completed B wells and drilling the A wells that correspond to those B wells. So what that means is, to be safe, we need to go ahead and shut in the associated B wells. So, it's a natural fact, as we go to an A campaign, we're shutting in B wells.

So it's really a mix of things, but suffice it to say, shut-in wells should be essentially linear with activity levels.

Got it. That's a helpful framework. And then, if I could ask a question about the chart you guys put up on these Version 3.0 completions, it looks very encouraging the uplift you see versus a Version 2.0. I understand that there is a problem about apples and oranges comparison because of your choked management on the flow back. But I'm wondering if maybe you can add some other parameters that maybe you guys are looking at that we haven't shown on these charts, like perhaps the pressure draw down by day that may be giving you either -- I expect added encouragement, but maybe just fill out the picture a little bit more on your enthusiasm for the Version 3.0.

Yes, Charles. One of the things that we do any time any we have a design change of this significance and particularly with the fact that we are doing so much choking is we are a heavy user of downhole gauges. You know, if you don't have the downhole gauges, you're basing everything based on a calculation that has a lot of uncertainty in it.

So we do put downhole gauges anytime we have a change like this, and what I can tell you is that the data we see from that is very optimistic, and it helps us feel that we understand the downside of the choking and the upside of the un-choked production.

You know, the other part of it that's been emphasized a couple of times, that I think is the most important indication, is the reality of adoption. You know, what I've discovered is that typically good news stays good news over the entire life of the well, and then sometimes news that may seem uncertain works itself out over in time and becomes good news. So, the areas where we start to see good news on the early parts of the well, that leads us to have early adoption as opposed to wait to do something different.

So, for me, the latter part tells us that the technical works been done, and we've made a decision to adopt and go forward.

Got it. That's helpful detail, Joey. Thank you.

Arun Jayaram, JPMorgan.

I wanted to just clarify some of your outlook comments for 2017. Scott, you talked about a 62% oil mix, 13% to 17% growth, and CapEx at $2.75 billion kind of at the midpoint.

My question is, does the $2.75 billion contemplate 17 rigs next year, and is that an all-in number including infrastructure spend?

Yes, this is Frank. The answer is it includes running 17 rigs all year. The thing that you're probably thinking about, if you have a sense that maybe that number is a little high, is remember that we are drilling more wells now -- maybe 15, 16 wells a year with the same number of rigs, and we're completing those. Our completion costs, while overall they've been coming down, if we go to all 3.0 wells next year, that would have a tendency to skew that number up.

On infrastructure, with more activity, we'll probably be spending at least the same if not more on tank batteries. We do have a new target plant that we will have a 27% interest in to pay next year. But probably if you look at our other spending, this year I think we spent something like $150 million. And if you'll remember when we've talked about our forecast going forward, and this model that Rich and his guys have put together, we've been spending about $300 million for vertical integration, water, those type of expenditures.

Next year, I would anticipate with our water buildout -- because you saw in Joey's slide, we are the league leader in number of wells that we're drilling and putting on production -- we're going to need a hell of a lot of water with these bigger fracs. So we're going to extend the scope of our mainline from the South into the North. We will likely start up the new Midland project next year to take water from the city of Midland. So I would not be surprised to see that other infrastructure or other capital number at least double and probably go a little bit higher than that next year.

Again, those numbers are in flux. So, we're giving you $2.7 billion to $2.8 billion, and it's kind of a preliminary number. But based on the early work we've done, that's probably within the area that we think we are going to spend.

Very helpful, Frank.

My follow-up is I was wondering about your thoughts on potentially taking advantage of the strong A&D in the market in the Permian. I know when you did the Devon transaction, you guys highlighted maybe opportunities to sell some non-core acres. I was wondering if you could highlight where you're at in terms of that process.

Sure. First of all, as you know, we're extremely pleased with the Devon transaction as the Sale Ranch acres that comes with that is really some of our very best acreage. And that's why that transaction was so important to us to accomplish.

We do believe those types of transactions will be relatively few and far between. It's hard to find inventory out there that's as good as what we own and an inventory that would then have the effect of high-grading our own inventory.

That said, we think when we do a transaction like the Devon transaction, we should also carve some assets off the bottom of our portfolio, and toward that end, we have three individual efforts underway, one of which is in full gate right now. This is a he sale of some acreage in Andrews County, it's about 7000 net acres, and we are right in the process of the data room work on that.

In addition, I think it will be later this year, and perhaps we will extend into next year a 20,000-acre or so package in Northeast Martin County. And it's possible we have one smaller package in addition.

So, we'll see how those things go. But our whole objective here is to be able to say that a transaction like Devon is net/net, when all the smoke clears, very accretive to our portfolio.

Great. Scott, good luck in retirement, and thanks for all your help over the years. I really appreciate it.

Neil Dingmann, SunTrust.

Say, just on type of well focus for next year and I mean for this year you mentioned about 60% Bs, 25% As and 15% in lower Spraberry. Do you anticipate kind of similar plans next year?

I do expect kind of similar plan. The only thing I would say that you would see some skew towards is more Wolfcamp A wells. You'll start to see a larger percentage of those because of our delayed A strategy. But, as far as Lower Spraberry, shale is similar, and then we'll be considering -- we'll be going into five different new areas, most likely, so we'll maybe have some appraisal, and we're still developing what we believe the well mix to be for those areas.

Okay. Makes sense. And then just lastly, what do you anticipate on the export cargoes for next year? It was great to see those start up. Just what type of growth you anticipate next year there? Thank you.

Well, in our case, as Scott mentioned, we have already exported two cargoes. There's one actually that's going to be exported, Pioneer at, I think it's next week, and we'll look at that from time to time. It really has to do, of course, with the arbitrage opportunity presented by international crude prices -- in this case, Brent -- which WTI squares up against nicely in terms of quality and WTI prices in the United States.

And so, over the last -- actually since the export ban when Scott was so instrumental in bringing it to fruition, what's happened is you've had a situation which you'd expect, which is where the two crews end up differing only by their transportation differentials. And that means there's not a lot of juice in terms of exporting.

Now, we have made money exporting, but it's not significant to the overall value of the barrel. However, moving it out of the United States when we are in a relatively high inventory situation I think net/net makes sense, especially when you can add the margin to the value of those barrels.

So you'll continue to see us looking at those opportunities as one of many opportunities for the final disposition of our sales. And that will be fairly true to the rest of the industry. The rest of the industry is up. I think our total exports have been exceeding 500,000 barrels a day, including Canada, and that could increase through time.

But, again, now we are talking about an economic proposition. We're not talking about a situation where we are forcing it to happen. It will happen to the extent the values are there.

Great details. Thanks, again.

Paul Sankey, Wolfe Research.

Hi, guys. Just thinking about what you were saying about the oil market. For next year, you sound very bearish on prices. Is that fair to say, I mean that we will be expecting to be seeing lower than $50 crude over the coming couple of years?

And secondly, could you just remind us why you maintained such aggressive levels of activity if you are so bearish on the price? Thank you.

Yes, Paul, I think the first comment is that obviously with the large build this morning just announced some 15 minutes ago that's putting pressure on prices, that may increase. In fact, the lower it goes between now and November 30, if it moves towards $40, it will put pressure on OPEC. I'd probably raise my 40% chance up.

I mean, coming together, because they can't afford to have another year of low $40s. Regardless of cuts, the market balances in 2018, so I expect oil to be back up into the mid-$50s or higher in 2018.

So, next year is a big swing year. We are hedged. I'm not worried about it. But it could be if OPEC fails in this agreement, we could easily see another year in the low $40s in 2017.

And Paul, in answer to your second question, I would say simply submit that. If you look at our actual cash costs of drilling these horizontal wells, including full boat burdens, including interest per BOE, G&A per BOE, it's about $20 per barrel. So that's why we are drilling wells when it's $50.

Yes, that's a pretty simple answer and makes sense, and thanks for the comments on OPEC.

Brian Singer, Goldman Sachs.

Thank you. Good morning and congratulations, again.

You mentioned briefly, some of the differences that you're seeing in the Upper B versus the Lower B. And so I wondered if you could update us on the relative well performance and the aerial extent of the examples where you've drilled an upper B on top of a lower B in the same unit.

No, so far we haven't done any upper B on lower B. It's really just a matter of identifying what the best target is in any particular zone, and it varies. We particularly find that the Lower B interval is more productive in the southern JV area. We've got some other areas in the central area that also have better productivity.

So, at this point in time, it's just more a matter of targeting, but we haven't done any Upper B/Lower B combinations yet.

And the only thing I would add to that, Joey, is that, as you go further south, we're talking about 800 feet of combined Upper and Lower Bs. And that would afford us probably more opportunity for the stacked B drilling compared to the North where it ends up sending out to maybe around 400 feet. So part of it will be just that simple amount of thickness which will dictate where we will drill those stacked wells when the time comes.

Got it. And is that in the plan for 2017 to drill a stacked deck -- stacked wells, or is that longer term?

It's being discussed. I haven't decided yet.

Okay. Thanks. And then on operating costs, your slide 18 has a helpful -- continues to have a helpful breakout of the operating costs by region. Can you just discuss your expectations over the next -- over 2017 and maybe 2018? And on one end the horizontals that are online decline, but then you are accelerating the amount of horizontal pops, and then in any industry inflation or other inflation you may see?

Yes, I think the way I would consider that, Brian, is that as we continue to increase activity levels, by definition we keep a ceiling on this production-cost number. That is to the extent other, older wealth are declining, their operating cost per BOE goes up by definition. We matched it up with more new wells with higher volumes in an attempt to supersede those declines.

So I think you'll reach some sort of (inaudible) before too long where that's going to be the case, and it's probably in the low [2s].

As it relates to inflation, production cost is probably the one area where we have risks of inflation. It is because the majority of production costs are things like personnel, chemicals and power, all of which are very difficult for us to hedge in any significant way.

So, if we have any risk of inflation, that's probably where it is.

Now, I think if you look at the State of Texas, power costs are extremely low. We benefit from wind power here substantially because of that.

We've got great chemical contracts. I think the labor workforce will probably be needing some bumps in this to compensate, just to get more workers back in the basin. But I think we control a lot of that, and I don't really see any substantial risk of any really serious blowout when it comes to inflation hurting our production costs.

Great. Thank you.

Pearce Hammond, Piper Jaffray.

Thanks, and Scott, all the best to you and Kim in your retirement.

My first question on -- you have a helpful slide on page 11 of your deck. It shows drilling and completion costs per perforated lateral foot, and it's obviously come down over time. It looks like that rate of descent, though, has slowed, Q2 to Q3. And so, I guess in the big picture, Tim, do you think that we could actually start to see this number go up with either service costs inflation or just more the Version 3.0 completions working their way through the system?

Yes, I think to the extent that we have, as Frank had mentioned, a substantial number of wells in our 2017 campaign that are Version 3.0, and I think that's the way we're leaning today, then that has to be offset by further productivity gains and/or cost savings.

I think that one thing we'll benefit from is we have several rigs that are -- that we are now bringing out of stack. We'll have essentially no stacked rig costs for most of 2017. And several of those rigs, at least half of those rigs come off existing contracts that were, at the time of their signing, at something like $26,000 a day. We will re-sign those at whatever the then current market is. Today it's maybe 14 or so.

So, we could see a savings that comes from that. I think we'll continue to nickel and dime away at these costs, but you're right: to the extent we mix in more 3.0s, we could see the numberis sort of bottoming out.

As to the inflation effects here, here I think we are very well-protected. We can argue all day long about when service companies are going to have pricing power, but the fact is we're doing our own completions. We have five fleets running today. We know what the costs of those are, so we're not going to be subject to cost increases on completions, which is, as you know, by far the biggest cost of the wells. And, in fact, we may have reductions in drilling costs, as I mentioned.

So, I think overall we are well-protected from any kind of inflationary issues that comes to our capital program. And I think that will continue through 2017, and for my money I don't think the service companies will have a lot of pricing power until we get well into 2018, and that's predicated on higher prices.

Excellent. Thanks for that answer, Tim. And then follow up, just housekeeping, just to make sure I understand this right. So, on this preliminary 2017 CapEx sort of between $2.7 billion up to $2.8 billion, what's the price deck you are assuming for that?

That's going to be basically 50 to 55 (multiple speakers) associated with the strip.

It's the strip.

Thank you.

Jeffrey Campbell, Tuohy Brothers.

Good morning and I'd like to echo the compliments to Scott and not only for the great job you did building Pioneer, but also the wonderful job he's done in grooming management to carry on after his retirement.

Thank you.

My first question is, when do the Version 3.0 wells go off of choke management?

Typically two to three weeks or four weeks into their lives.

Okay. Thanks. That's very helpful.

Bearing in mind that their outperformance -- I'm just wondering, if you didn't have the water-management issue, do you think you would choke the Version 3.0 wells anyway? Perhaps it's having a positive influence on shallower decline.

No, we don't really right now believe that there's any long-term impact, positive or negative on choking the wells back. Is it simply a surface equipment utilization issue we're dealing with? And so I think if it were not for that, if we had infinite amount of capacity for water handling, all these wells would be on full production.

Okay. Thank you. And then last question I'd like to ask real quick, going back to slide 18, it shows that Pioneer's assets, other than the Permian and the Eagle Ford, are fairly low margin, primarily because they are so gassy, as is illustrated on slide 22. Just wondering if you had any thoughts on simplifying the portfolio over time, maybe raising some cash for more higher-margin drilling by selling these assets.

Well, I think we look at our company and say everything in the company is for sale every day. And so we kind of look at things that way.

I think it's certainly the case that some of these assets are areas where we are not utilizing much capital. But by the same token, they would stand to benefit significantly with increases in commodity prices. As you said, if we see any kind of bump in gas, Eagle Ford economics improved considerably. That's certainly true of our Mid-Continent assets as well. In fact, we're taking a look at a drilling campaign for Eagle Ford next year with that in mind with our partner.

So, suffice it to say, everything will look at is for sale, but we right now aren't contemplating any particular sale of the types you're talking about.

Matt Portillo, TPH.

Just a quick clarification on the 2017 CapEx. I just wanted to make sure I understood. So, from a capital perspective, is it fair to assume that you are baking in the Version 3.0 fracs for the wells that you are drilling next year? And then commensurate with that, you have not yet baked in Version 3.0 fracs for your production guidance?

That's right.

Everything for 2017 is still 2.0-based.

Right.

On the production side -- but for the capital side, you have baked in the Version 3.0 fracs?

No, we haven't. I just mentioned that that could be an increase above what we already have, if it turns out that we decide to go with, say the majority 3.0s.

Great. Thank you very much. And then just the second question, a follow-up to the previous question on the Eagle Ford: could you frame any context or color around how you think about adding back activity to the play and maybe what some of the drivers might be behind that? If and when you do consider it?

Certainly. I think as I mentioned a minute ago, Matt, commodity prices are a big player here, and in this particular case, where we operate in the play, the price of natural gas and NGLs become critical to the play. And particularly on the NGL front, ethane price is about 40% of what we produce in NGLs in Eagle Ford or ethane.

We have seen some cooperation with gas prices. Now, some of that's peeled back. Ethane prices have done essentially the same thing. I think ethane has some potential for improvement as we get into 2017 and 2018.

So, the economics certainly have some room to improve from here before we make those decisions, but that will certainly be the number one factor.

Of course, in association with our obligations to Enterprise and our throughput agreements in the Eagle Ford, we have minimum daily requirements for efficiency fees if we don't meet those, and we could offset some of those by drilling, which would be a positive as well.

Great. Thank you very much.

James Sullivan, Alembic Global Advisors.

I just wanted to come back to something -- most of you guys have asked and answered most of the questions already. But in the discussion about offset fracs, you guys talked about coming in with your layering in the Wolfcamp As over the existing Bs, I think. And could you just remind us what information you guys have, if any, about communication between laterals? I mean, you do that -- and whether that information, if you do have it, is based off of older completions signs which were -- used less of the near well bore fracturing and -- yes, just any update you guys might have on that?

Yes, we have quite a bit of data on communication, of course. As you go across the field as the frac barrier varies, the communication varies as well. But, generally speaking, whenever we do stimulate an A well, we're going to shut in the B wells, and we're going to shut them in until the A well is drilled out and then bring them back online continuously. We've done quite a bit of interference testing over the last couple of years to understand the communication between the two.

You know, it's not similar across the entire field. It varies, again based on the frac barrier strength. But I do believe we have a really good feeling for the way that those wells do communicate. But we certainly don't want to deteriorate the quality of an A well by not shutting in that B well. So we feel strongly enough to where we are going to do that consistently.

Okay. And has there been -- do you have any evidence of a synergistic frac when you bring that B back on? Does it come in at a higher rate, or is there any -- no evidence of that in place of where the frac barrier is (technical difficulty)?

Similar to the Eagle Ford, you know, the initial comeback is sometimes better, sometimes worse, but what we see over time is that they come back to what we expect.

And that does conclude our question-and-answer session for today. I would like to turn the conference back over to Mr. Dove for any additional or closing remarks.

Thanks very much.

Well, once again, thank you for listening to us in this call. We wish all of you happy holidays and safe travels as we go through the end of the year, and we'll certainly be -- have some meetings outside on the road, but at the very least we expect to be able to be -- give you some more good data on 3.0 Version completions in our February call regarding the fourth quarter.

Thanks very much for participating.

And, once again, that does conclude today's conference. We thank you all for your participation. You may now disconnect.